S-1/A

As filed with the Securities and Exchange Commission on October 10, 2012

Registration No. 333-182305

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Amendment No. 5

to

Form S-1

LINNCO, LLC

LINN ENERGY, LLC

(Exact Name of Registrant as Specified in its charter)

Delaware	1311	45-5166623
Delaware		65-1177591
(State or other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(IRS Employer Identification Number)

600 Travis, Suite 5100

Houston, Texas 77002

(281) 840-4000

(Address, including Zip Code, and Telephone Number including Area Code, of Registrant’s Principal Executive Offices)

Candice J. Wells	Charlene A. Ripley
600 Travis, Suite 5100 Houston, Texas 77002 (281) 840-4000	600 Travis, Suite 5100 Houston, Texas 77002 (281) 840-4000

(Name, Address, including Zip Code, and Telephone Number including Area Code, of Agent for Service)

Copies to:

Kelly Rose Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002-4995 (713) 229-1234 J. Michael Chambers Brett E. Braden Latham & Watkins LLP 811 Main Street Suite 3700 Houston, Texas 77002 (713) 546-5400

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

LinnCo, LLC — Non-accelerated filer

Linn Energy, LLC — Large accelerated filer

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

EXPLANATORY NOTE

LinnCo, LLC and Linn Energy, LLC are filing this Amendment No. 5 (the “Amendment”) to the Registration Statement on Form S-1 (File Nos. 333-182305 and 333-182305-01) (the “Registration Statement”) as an exhibit-only filing to submit certain financial statements of Linn Energy, LLC formatted in XBRL (eXtensible Business Reporting Language), attached hereto as Exhibit 101, and the fourth amendment to Linn Energy, LLC’s Fifth Amended and Restated Credit Agreement dated as of May 2, 2011, attached hereto as Exhibit 10.31, and to amend and restate the list of exhibits set forth in Item 16 of Part II of the Registration Statement. Accordingly, this Amendment consists only of the facing page, this explanatory note, Item 16 of Part II of the Registration Statement, the signature pages to the Registration Statement and the filed exhibits. The prospectus and Items 13, 14, 15 and 17 of Part II are unchanged and have been omitted.

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 16. Exhibits and Financial Statement Schedules.

The following documents are filed as exhibits to this registration statement:

Number		Description
1.1*	—	Form of Underwriting Agreement
3.1*	—	Certificate of Formation of LinnCo, LLC
3.2*	—	Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)
3.3*	—	Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S-1 (File No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)
3.4*	—	Form of Amended and Restated Limited Liability Company Agreement of LinnCo, LLC
3.5*	—	Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Current Report on Form 8-K filed on September 7, 2010)
3.6*	—	Certificate of Amendment, dated September 6, 2012, to Certificate of Formation of LinnCo, LLC
4.1*	—	Form of specimen unit certificate for the units of Linn Energy, LLC (incorporated herein by reference to Exhibit 4.1 to Annual Report on Form 10-K for the year ended December 31, 2005, filed on May 31, 2006)
4.2*	—	Indenture, dated as of June 27, 2008, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 30, 2008)
4.3*	—	Indenture, dated May 18, 2009, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U. S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on May 18, 2009)
4.4*	—	Indenture, dated as of April 6, 2010, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on April 9, 2010)
4.5*	—	Indenture, dated as of September 13, 2010, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 13, 2010)
4.6*	—	Indenture, dated May 13, 2011, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on May 16, 2011)
4.7*	—	First Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of June 27, 2008, between Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Quarterly Report on Form 10-Q filed on July 29, 2010)
4.8*	—	First Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of May 18, 2009, between Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed on July 29, 2010)

II-1

Number		Description
4.9*	—	First Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of April 6, 2010, between Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed on July 29, 2010)
4.10*	—	Second Supplemental Indenture, dated as of March 16, 2011, to the Indenture, dated as of May 18, 2009, by and among Linn Energy LLC, Linn Energy Finance Corp., the Guarantors party thereto and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 22, 2011)
4.11*	—	Second Supplemental Indenture, dated as of March 16, 2011, to the Indenture dated as of June 27, 2008, by and among Linn Energy LLC, Linn Energy Finance Corp., the Guarantors party thereto and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 22, 2011)
4.12*	—	Registration Rights Agreement, dated May 13, 2011, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed on May 16, 2011)
4.13*	—	Indenture, dated March 2, 2012, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U. S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 2, 2012)
4.14*	—	Registration Rights Agreement, dated March 2, 2012, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 2, 2012)
5.1*	—	Opinion of Baker Botts L.L.P. as to the legality of the securities being registered
8.1*	—	Opinion of Baker Botts L.L.P. relating to tax matters
10.1*	—	Form of Omnibus Agreement
10.2*	—	Linn Energy, LLC Amended and Restated Long-Term Incentive Plan (incorporated herein by reference to Annex A to the Proxy Statement for 2008 Annual Meeting, filed on April 21, 2008)
10.3*	—	Amendment No. 1 to Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, dated February 4, 2009, (incorporated herein by reference to Exhibit 10.2 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.4*	—	Amendment No. 2 to Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, dated July 19, 2010, (incorporated herein by reference to Exhibit 10.3 to Quarterly Report on Form 10-Q filed on July 29, 2010)
10.5*	—	Form of Executive Unit Option Agreement pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.3 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.6*	—	Form of Executive Restricted Unit Agreement pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.4 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.7*	—	Form of Phantom Unit Grant Agreement for Independent Directors pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 9, 2006)
10.8*	—	Form of Director Restricted Unit Grant Agreement pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.6 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)

II-2

Number		Description
10.9*	—	Retirement Agreement, dated as of November 29, 2011, by and among Linn Operating, Inc., Linn Energy, LLC and Michael C. Linn (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on December 1, 2011)
10.10*	—	Third Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Kolja Rockov (incorporated herein by reference to Exhibit 10.8 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.11*	—	Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Mark E. Ellis (incorporated herein by reference to Exhibit 10.9 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.12*	—	Amendment No. 1, dated effective as of January 1, 2010, to Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Mark E. Ellis (incorporated herein by reference to Exhibit 10.29 to Annual Report on Form 10-K for the year ended December 31, 2009, filed on February 25, 2010)
10.13*	—	Amended and Restated Employment Agreement, dated effective December 17, 2008, between Linn Operating, Inc. and Charlene A. Ripley (incorporated herein by reference to Exhibit 10.10 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.14*	—	Amended and Restated Employment Agreement, dated effective December 17, 2008, between Linn Operating, Inc. and Arden L. Walker, Jr. (incorporated herein by reference to Exhibit 10.11 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.15*	—	Amendment No. 1, dated April 26, 2011, to First Amended and Restated Employment Agreement, dated December 17, 2008, between Linn Operating, Inc. and Arden L. Walker, Jr. (incorporated herein by reference to Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed on April 28, 2011)
10.16*	—	Second Amended and Restated Employment Agreement, dated December 17, 2008, between Linn Operating, Inc. and David B. Rottino (incorporated herein by reference to Exhibit 10.12 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.17*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and George A. Alcorn (incorporated herein by reference to Exhibit 10.15 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.18*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Joseph P. McCoy (incorporated herein by reference to Exhibit 10.16 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.19*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Terrence S. Jacobs (incorporated herein by reference to Exhibit 10.17 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.20*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Jeffrey C. Swoveland (incorporated herein by reference to Exhibit 10.18 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.21*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Michael C. Linn (incorporated herein by reference to Exhibit 10.19 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.22*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Mark E. Ellis (incorporated herein by reference to Exhibit 10.20 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)

II-3

Number		Description
10.23*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Kolja Rockov (incorporated herein by reference to Exhibit 10.21 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.24*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Charlene A. Ripley (incorporated herein by reference to Exhibit 10.22 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.25*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and David B. Rottino (incorporated herein by reference to Exhibit 10.23 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.26*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Arden L. Walker, Jr. (incorporated herein by reference to Exhibit 10.24 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.27*	—	Fifth Amended and Restated Credit Agreement dated as of May 2, 2011, among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and agents Party thereto (incorporated herein by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on July 28, 2011)
10.28*	—	First Amendment to Fifth Amended and Restated Credit Agreement, dated February 29, 2012, among Linn Energy, LLC, BNP Paribas, as administrative agent, and the other agents and lenders party thereto (incorporated herein by reference to Exhibit 1.2 to Current Report on Form 8-K filed on March 2, 2012)
10.29*	—	Second Amendment to Fifth Amended and Restated Credit Agreement, dated May 10, 2012, among Linn Energy, LLC, Wells Fargo Bank, National Association, as administrative agent, and the other agents and lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed on May 15, 2012)
10.30*	—	Third Amendment to Fifth Amended and Restated Credit Agreement, dated July 25, 2012, among Linn Energy, LLC, Wells Fargo Bank, National Association, as administrative agent, and the other agents and lenders party thereto (incorporated herein by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q filed on July 26, 2012)
10.31	—	Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated September 28, 2012, among Linn Energy, LLC, Wells Fargo, National Association, as administrative agent, and the other agents and lenders party thereto
10.32*	—	Fifth Amended and Restated Guaranty and Pledge Agreement, dated as of May 2, 2011, made by Linn Energy, LLC and each of the other Obligors in favor of BNP Paribas, as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on July 28, 2011)
10.33*	—	Linn Energy, LLC Change of Control Protection Plan, dated as of April 25, 2009, (incorporated herein by reference to Exhibit 10.3 to Quarterly Report on Form 10-Q filed on May 7, 2009)
10.34*	—	Salt Creek EOR Participation Agreement, dated April 3, 2012, by and between Howell Petroleum Corporation and Linn Energy Holdings, LLC (incorporated herein by reference to Exhibit 10.2 to Quarterly Report on form 10-Q filed on April 26, 2012)
21.1*	—	List of Subsidiaries of Linn Energy, LLC (incorporated herein by reference to Exhibit 21.1 to Annual Report on Form 10-K for the year ended December 31, 2011, filed on February 23, 2012)
23.1*	—	Consent of KPMG LLP
23.2*	—	Consent of Ernst & Young LLP
23.3*	—	Consent of DeGolyer & MacNaughton
23.4*	—	Consent of Baker Botts L.L.P. (contained in Exhibit 5.1)

II-4

Number		Description
23.5*	—	Consent of Baker Botts L.L.P. (contained in Exhibit 8.1)
23.6*	—	Consent of Baker Botts L.L.P.
24.1*	—	Powers of Attorney (contained on the signature page to this Registration Statement)
99.1*	—	2011 Report of DeGolyer & MacNaughton (incorporated herein by reference to Exhibit 99.1 to Annual Report on Form 10-K for the year ended December 31, 2011 filed on February 23, 2012)
99.2*	—	2012 Report of DeGolyer & MacNaughton (Hugoton Acquisition)
99.3*	—	2012 Report of DeGolyer & MacNaughton (East Texas Acquisition)
99.4*	—	2012 Report of DeGolyer & MacNaughton (Anadarko Joint Venture)
99.5*	—	2012 Report of DeGolyer & MacNaughton (Green River Acquisition)
101	—	The following financial statements and footnotes of Linn Energy, LLC, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of December 31, 2011 and December 31, 2010, (ii) Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009, (iii) Consolidated Statements of Unitholders’ Capital for the years ended December 31, 2011, 2010 and 2009, (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009, (v) Notes to Consolidated Financial Statements, (vi) Condensed Consolidated Balance Sheets as of June 30, 2012 (Unaudited) and December 31, 2011, (vii) Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2012 and June 30, 2011 (Unaudited), (viii) Condensed Consolidated Statement of Unitholders’ Capital for the six months ended June 30, 2012 (Unaudited), (ix) Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and June 30, 2011 (Unaudited) and (x) Notes to Condensed Consolidated Financial Statements (Unaudited).

* Previously filed

II-5

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on October 10, 2012.

LINNCO, LLC
By:	*
	Name: Kolja Rockov Title: Executive Vice President and Chief           Financial Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

Name	Title	Date
* Mark E. Ellis	Chairman, President and Chief Executive Officer; Director	October 10, 2012
* Kolja Rockov	Executive Vice President and Chief Financial Officer	October 10, 2012
* David B. Rottino	Senior Vice President and Chief Accounting Officer	October 10, 2012
* George A. Alcorn	Independent Director	October 10, 2012
* David D. Dunlap	Independent Director	October 10, 2012
* Terrence S. Jacobs	Independent Director	October 10, 2012

II-6

Name	Title	Date
* Michael C. Linn	Director	October 10, 2012
* Joseph P. McCoy	Independent Director	October 10, 2012
* Jeffrey C. Swoveland	Independent Director	October 10, 2012

*By:	/s/    Candice Wells
	Candice Wells Attorney-in-Fact

II-7

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on October 10, 2012.

LINN ENERGY, LLC
By:	*
	Name: Kolja Rockov Title: Executive Vice President and Chief           Financial Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

Name	Title	Date
* Mark E. Ellis	Chairman, President and Chief Executive Officer; Director	October 10, 2012
* Kolja Rockov	Executive Vice President and Chief Financial Officer	October 10, 2012
* David B. Rottino	Senior Vice President of Finance, Business Development and Chief Accounting Officer	October 10, 2012
* George A. Alcorn	Independent Director	October 10, 2012
* David D. Dunlap	Independent Director	October 10, 2012
* Terrence S. Jacobs	Independent Director	October 10, 2012

II-8

Name	Title	Date
* Michael C. Linn	Director	October 10, 2012
* Joseph P. McCoy	Independent Director	October 10, 2012
* Jeffrey C. Swoveland	Independent Director	October 10, 2012

*By:	/s/    Candice Wells
	Candice Wells Attorney-in-Fact

II-9

EXHIBIT LIST

The following documents are filed as exhibits to this registration statement:

Number		Description
1.1*	—	Form of Underwriting Agreement
3.1*	—	Certificate of Formation of LinnCo, LLC
3.2*	—	Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)
3.3*	—	Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S-1 (File No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)
3.4*	—	Form of Amended and Restated Limited Liability Company Agreement of LinnCo, LLC
3.5*	—	Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Current Report on Form 8-K filed on September 7, 2010)
3.6*	—	Certificate of Amendment, dated September 6, 2012, to Certificate of Formation of LinnCo, LLC
4.1*	—	Form of specimen unit certificate for the units of Linn Energy, LLC (incorporated herein by reference to Exhibit 4.1 to Annual Report on Form 10-K for the year ended December 31, 2005, filed on May 31, 2006)
4.2*	—	Indenture, dated as of June 27, 2008, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 30, 2008)
4.3*	—	Indenture, dated May 18, 2009, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on May 18, 2009)
4.4*	—	Indenture, dated as of April 6, 2010, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on April 9, 2010)
4.5*	—	Indenture, dated as of September 13, 2010, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 13, 2010)
4.6*	—	Indenture, dated May 13, 2011, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on May 16, 2011)
4.7*	—	First Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of June 27, 2008, between Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 to Quarterly Report on Form 10-Q filed on July 29, 2010)
4.8*	—	First Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of May 18, 2009, between Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed on July 29, 2010)

II-10

Number		Description
4.9*	—	First Supplemental Indenture, dated as of July 2, 2010, to Indenture, dated as of April 6, 2010, between Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed on July 29, 2010)
4.10*	—	Second Supplemental Indenture, dated as of March 16, 2011, to the Indenture, dated as of May 18, 2009, by and among Linn Energy LLC, Linn Energy Finance Corp., the Guarantors party thereto and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 22, 2011)
4.11*	—	Second Supplemental Indenture, dated as of March 16, 2011, to the Indenture dated as of June 27, 2008, by and among Linn Energy LLC, Linn Energy Finance Corp., the Guarantors party thereto and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 22, 2011)
4.12*	—	Registration Rights Agreement, dated May 13, 2011, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed on May 16, 2011)
4.13*	—	Indenture, dated March 2, 2012, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 2, 2012)
4.14*	—	Registration Rights Agreement, dated March 2, 2012, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and the representatives of the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 2, 2012)
5.1*	—	Opinion of Baker Botts L.L.P. as to the legality of the securities being registered
8.1*	—	Opinion of Baker Botts L.L.P. relating to tax matters
10.1*	—	Form of Omnibus Agreement
10.2*	—	Linn Energy, LLC Amended and Restated Long-Term Incentive Plan (incorporated herein by reference to Annex A to the Proxy Statement for 2008 Annual Meeting, filed on April 21, 2008)
10.3*	—	Amendment No. 1 to Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, dated February 4, 2009, (incorporated herein by reference to Exhibit 10.2 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.4*	—	Amendment No. 2 to Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, dated July 19, 2010, (incorporated herein by reference to Exhibit 10.3 to Quarterly Report on Form 10-Q filed on July 29, 2010)
10.5*	—	Form of Executive Unit Option Agreement pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.3 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.6*	—	Form of Executive Restricted Unit Agreement pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.4 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.7*	—	Form of Phantom Unit Grant Agreement for Independent Directors pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 9, 2006)

II-11

Number		Description
10.8*	—	Form of Director Restricted Unit Grant Agreement pursuant to the Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (incorporated herein by reference to Exhibit 10.6 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.9*	—	Retirement Agreement, dated as of November 29, 2011, by and among Linn Operating, Inc., Linn Energy, LLC and Michael C. Linn (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on December 1, 2011)
10.10*	—	Third Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Kolja Rockov (incorporated herein by reference to Exhibit 10.8 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.11*	—	Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Mark E. Ellis (incorporated herein by reference to Exhibit 10.9 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.12*	—	Amendment No. 1, dated effective as of January 1, 2010, to Amended and Restated Employment Agreement, dated effective as of December 17, 2008, between Linn Operating, Inc. and Mark E. Ellis (incorporated herein by reference to Exhibit 10.29 to Annual Report on Form 10-K for the year ended December 31, 2009, filed on February 25, 2010)
10.13*	—	Amended and Restated Employment Agreement, dated effective December 17, 2008, between Linn Operating, Inc. and Charlene A. Ripley (incorporated herein by reference to Exhibit 10.10 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.14*	—	Amended and Restated Employment Agreement, dated effective December 17, 2008, between Linn Operating, Inc. and Arden L. Walker, Jr. (incorporated herein by reference to Exhibit 10.11 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.15*	—	Amendment No. 1, dated April 26, 2011, to First Amended and Restated Employment Agreement, dated December 17, 2008, between Linn Operating, Inc. and Arden L. Walker, Jr. (incorporated herein by reference to Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed on April 28, 2011)
10.16*	—	Second Amended and Restated Employment Agreement, dated December 17, 2008, between Linn Operating, Inc. and David B. Rottino (incorporated herein by reference to Exhibit 10.12 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.17*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and George A. Alcorn (incorporated herein by reference to Exhibit 10.15 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.18*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Joseph P. McCoy (incorporated herein by reference to Exhibit 10.16 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.19*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Terrence S. Jacobs (incorporated herein by reference to Exhibit 10.17 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.20*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Jeffrey C. Swoveland (incorporated herein by reference to Exhibit 10.18 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.21*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Michael C. Linn (incorporated herein by reference to Exhibit 10.19 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.22*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Mark E. Ellis (incorporated herein by reference to Exhibit 10.20 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)

II-12

Number		Description
10.23*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Kolja Rockov (incorporated herein by reference to Exhibit 10.21 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.24*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Charlene A. Ripley (incorporated herein by reference to Exhibit 10.22 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.25*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and David B. Rottino (incorporated herein by reference to Exhibit 10.23 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.26*	—	Indemnity Agreement, dated as of February 4, 2009, between Linn Energy, LLC and Arden L. Walker, Jr. (incorporated herein by reference to Exhibit 10.24 to Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 26, 2009)
10.27*	—	Fifth Amended and Restated Credit Agreement dated as of May 2, 2011, among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and agents Party thereto (incorporated herein by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on July 28, 2011)
10.28*	—	First Amendment to Fifth Amended and Restated Credit Agreement, dated February 29, 2012, among Linn Energy, LLC, BNP Paribas, as administrative agent, and the other agents and lenders party thereto (incorporated herein by reference to Exhibit 1.2 to Current Report on Form 8-K filed on March 2, 2012)
10.29*	—	Second Amendment to Fifth Amended and Restated Credit Agreement, dated May 10, 2012, among Linn Energy, LLC, Wells Fargo Bank, National Association, as administrative agent, and the other agents and lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed on May 15, 2012)
10.30*	—	Third Amendment to Fifth Amended and Restated Credit Agreement, dated July 25, 2012, among Linn Energy, LLC, Wells Fargo Bank, National Association, as administrative agent, and the other agents and lenders party thereto (incorporated herein by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q filed on July 26, 2012)
10.31	—	Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated September 28, 2012, among Linn Energy, LLC, Wells Fargo, National Association, as administrative agent, and the other agents and lenders party thereto
10.32*	—	Fifth Amended and Restated Guaranty and Pledge Agreement, dated as of May 2, 2011, made by Linn Energy, LLC and each of the other Obligors in favor of BNP Paribas, as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on July 28, 2011)
10.33*	—	Linn Energy, LLC Change of Control Protection Plan, dated as of April 25, 2009, (incorporated herein by reference to Exhibit 10.3 to Quarterly Report on Form 10-Q filed on May 7, 2009)
10.34*	—	Salt Creek EOR Participation Agreement, dated April 3, 2012, by and between Howell Petroleum Corporation and Linn Energy Holdings, LLC (incorporated herein by reference to Exhibit 10.2 to Quarterly Report on form 10-Q filed on April 26, 2012)
21.1*	—	List of Subsidiaries of Linn Energy, LLC (incorporated herein by reference to Exhibit 21.1 to Annual Report on Form 10-K for the year ended December 31, 2011, filed on February 23, 2012)
23.1*	—	Consent of KPMG LLP
23.2*	—	Consent of Ernst & Young LLP
23.3*	—	Consent of DeGolyer & MacNaughton
23.4*	—	Consent of Baker Botts L.L.P. (contained in Exhibit 5.1)
23.5*	—	Consent of Baker Botts L.L.P. (contained in Exhibit 8.1)

II-13

Number		Description
23.6*	—	Consent of Baker Botts L.L.P.
24.1*	—	Powers of Attorney (contained on the signature page to this Registration Statement)
99.1*	—	2011 Report of DeGolyer & MacNaughton (incorporated herein by reference to Exhibit 99.1 to Annual Report on Form 10-K for the year ended December 31, 2011 filed on February 23, 2012)
99.2*	—	2012 Report of DeGolyer & MacNaughton (Hugoton Acquisition)
99.3*	—	2012 Report of DeGolyer & MacNaughton (East Texas Acquisition)
99.4*	—	2012 Report of DeGolyer & MacNaughton (Anadarko Joint Venture)
99.5*	—	2012 Report of DeGolyer & MacNaughton (Green River Acquisition)
101	—	The following financial statements and footnotes of Linn Energy, LLC, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of December 31, 2011 and December 31, 2010, (ii) Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009, (iii) Consolidated Statements of Unitholders’ Capital for the years ended December 31, 2011, 2010 and 2009, (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009, (v) Notes to Consolidated Financial Statements, (vi) Condensed Consolidated Balance Sheets as of June 30, 2012 (Unaudited) and December 31, 2011, (vii) Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2012 and June 30, 2011 (Unaudited), (viii) Condensed Consolidated Statement of Unitholders’ Capital for the six months ended June 30, 2012 (Unaudited), (ix) Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and June 30, 2011 (Unaudited) and (x) Notes to Condensed Consolidated Financial Statements (Unaudited).

* Previously filed

II-14

EX-10.31

Exhibit 10.31

FOURTH AMENDMENT AND CONSENT

TO

FIFTH AMENDED AND RESTATED CREDIT AGREEMENT

DATED AS OF SEPTEMBER 28, 2012

AMONG

LINN ENERGY, LLC,

AS BORROWER,

THE GUARANTORS,

WELLS FARGO BANK, NATIONAL ASSOCIATION,

AS ADMINISTRATIVE AGENT,

ROYAL BANK OF CANADA,

AS SYNDICATION AGENT,

THE ROYAL BANK OF SCOTLAND PLC, CREDIT AGRICOLE CORPORATE AND INVESTMENT

BANK, CITIBANK, NA AND BARCLAYS BANK PLC,

AS CO-DOCUMENTATION AGENTS

AND

THE LENDERS PARTY HERETO

JOINT BOOK RUNNERS AND JOINT LEAD ARRANGERS

WELLS FARGO SECURITIES, LLC RBC CAPITAL MARKETS

FOURTH AMENDMENT AND CONSENT TO FIFTH AMENDED AND RESTATED CREDIT

AGREEMENT

THIS FOURTH AMENDMENT AND CONSENT TO FIFTH AMENDED AND RESTATED CREDIT AGREEMENT (this “Fourth Amendment”) dated as of September 28, 2012, among LINN ENERGY, LLC, a Delaware limited liability company, (the “Borrower”); the Guarantors signatory hereto, each of the Lenders party to the Credit Agreement referred to below; and WELLS FARGO BANK, NATIONAL ASSOCIATION (“Wells”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

R E C I T A L S

A. The Borrower, BNP Paribas (predecessor to the Administrative Agent) as the initial administrative agent, the Lenders and the other Agents party thereto entered into that certain Fifth Amended and Restated Credit Agreement dated as of May 2, 2011 as amended by that certain First Amendment dated as of February 29, 2012, that certain Second Amendment dated as of May 10, 2012 and that certain Third Amendment dated as of July 25, 2012 (the “Credit Agreement”), pursuant to which the Lenders have made certain credit and other financial accommodations available to and on behalf of the Borrower and its Subsidiaries.

B. The Borrower has informed the Administrative Agent and the Lenders of its entrance into and/or intent to enter into a series of transactions described in clauses (a) through (e) below (collectively, and together with any other actions related thereto, including the ongoing performance by the Borrower or any of its Affiliates of their obligations under any agreements, documents, instruments or other transactions related thereto, as more fully described in the Registration Statement on Form S-1 filed with the SEC on June 25, 2012 of the Borrower and LinnCo, LLC, a Delaware limited liability company and Subsidiary of the Borrower (“LinnCo”), including all exhibits filed therewith, and any subsequent amendments filed thereto and subsequent exhibits filed therewith prior to the date hereof, the “LinnCo Transactions”):

(a) The formation of LinnCo by the Borrower and the ownership by the Borrower of all of the voting Equity Interests of LinnCo.

(b) The purchase by public investors for cash, pursuant to an underwritten initial public offering, of limited liability company interests in LinnCo (the “IPO”), and purchases by public investors, for cash, of additional limited liability company interests in LinnCo from time to time pursuant to future equity offerings.

(c) The purchase by LinnCo of a number of Equity Interests in the Borrower equal to the number of LinnCo limited liability company interests sold in the IPO and in future equity offerings.

(d) The exclusion of LinnCo from the definition of “Subsidiary” set forth in the Credit Agreement, as amended hereby, and from all restrictions, conditions and obligations under the Credit Agreement, as amended hereby and other Loan Documents applicable to Subsidiaries.

(e) The entering into of, and performance of obligations under, an omnibus agreement and other management, services and administrative agreements between the Borrower and LinnCo.

C. The Borrower has requested and the Administrative Agent and the Lenders have agreed to amend certain provisions of the Credit Agreement.

D. NOW, THEREFORE, to induce the Administrative Agent and the Lenders to enter into this Fourth Amendment and in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1. Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement, as amended by this Fourth Amendment. Unless otherwise indicated, all section or article references in this Fourth Amendment refer to sections or articles of the Credit Agreement.

Section 2. Amendments to Credit Agreement.

2.1 Amendment to Section 1.02.

(a) Section 1.02 is hereby amended by deleting the defined terms “Agreement”, “Subsidiary” and “Swap Agreement” in their entirety and replacing them with the following respective terms:

“‘Agreement’ means this Credit Agreement, as amended by that certain First Amendment dated as of February 29, 2012, that certain Second Amendment dated as of May 10, 2012 , that certain Third Amendment dated as of July 25, 2012 and that certain Fourth Amendment dated as of September 28, 2012 as the same may from time to time be further amended, modified, supplemented or restated.

‘Subsidiary’ of a Person means (a) a corporation, partnership, joint venture, limited liability company or other business entity of which Equity Interests representing more than 50% of the ordinary voting power to elect a majority of the board of directors, managers or other governing body (irrespective of whether or not at the time Equity Interests of any other class or classes of such Person shall have or might have voting power by reason of the happening of any contingency) are at the time owned or controlled by such Person or one or more of its Subsidiaries or by such Person and one or more of its Subsidiaries, and (b) any partnership of which such Person or any of its Subsidiaries is a general partner. Unless otherwise indicated herein, each reference to the term “Subsidiary” means a Subsidiary of the Borrower. Notwithstanding the foregoing, in no event shall the terms “Subsidiary”, “Subsidiaries” or “subsidiary” contained in this Agreement or any other Loan Document include the Excluded Subsidiary unless expressly specified otherwise.

2

‘Swap Agreement’ means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, emissions reduction, carbon sequestration or other environmental protection credits, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Borrower or any of its Subsidiaries shall be a Swap Agreement.”

(b) Section 1.02 is hereby amended by adding the defined terms “Affiliate Services” and “Excluded Subsidiary” in the appropriate alphabetical order:

“‘Affiliate Services’ means the provision by the Borrower or any of its Subsidiaries to the Excluded Subsidiary of, and/or the procurement and payment by the Borrower or any of its Subsidiaries on behalf of the Excluded Subsidiary for, the following:

(a) legal, accounting, tax advisory, financial advisory, engineering and other professional or advisory services;

(b) administrative and management services;

(c) costs, fees and expenses incurred in connection with any public offering of Equity Interests in the Excluded Subsidiary, or incurred as a result of the Excluded Subsidiary being a publicly traded Person;

(d) cash management services, including treasury services, and the procurement of and payment for any insurance covering the Excluded Subsidiary;

(e) payment of usual and customary costs, fees and expenses of officers and directors, and provision of officers’ and directors’ indemnification and insurance in the ordinary course of business to the extent permitted by law; and

(f) indemnification for any costs, fees, expenses, damages or liabilities (other than liabilities for income Taxes) arising from (i) the ownership by the Excluded Subsidiary of Equity Interests in the Borrower or (ii) the Excluded Subsidiary carrying out its activities as described in the Registration Statement on Form S-1 of the Excluded Subsidiary and the Borrower filed with the SEC on June 25, 2012, including all exhibits filed therewith, and any subsequent amendments filed thereto and subsequent exhibits filed therewith prior to the date of the Fourth Amendment described in the definition of “Agreement”.

3

‘Excluded Subsidiary’ means LinnCo, LLC, a Delaware limited liability company, so long as it holds no assets, incurs no Debt and has no operations other than (a) its ownership of Equity Interests in the Borrower, and assets and operations incidental thereto and (b) other assets not to exceed $1,000,000 in the aggregate at any time outstanding.”

2.2 Amendment to Section 8.01(d). Section 8.01(d) is hereby amended by deleting the period at the end of the first sentence thereof and replacing it with the following:

“; provided that the Borrower shall not be required to provide any mark-to-market value for any emission credit Swap Agreements, but the Borrower shall provide the aggregate amount owing by the Borrower and its Subsidiaries under such emission credit Swap Agreements as of such date.”

2.3 Amendment to Section 9.05. Section 9.05 is hereby amended by adding the following as a new clause (p) thereto:

“(p) Investments in the Excluded Subsidiary consisting of any Affiliate Services.”

2.4 Amendment to Section 9.13. Section 9.13 is hereby amended by (a) removing the “and” from the end of clause (c) thereof, (b) removing the period at the end of clause (d) thereof and replacing such period with the following: “; and” and (c) adding the following as a new clause (e) thereto:

“(e) any Affiliate Services.”

2.5 Amendment to Section 9.14. Section 9.14 is hereby amended by (a) replacing the word “or” from the end of clause (d) thereof with a comma, (b) removing the period at the end of clause (e) thereof and replacing such period with the word “or” and (c) adding the following as a new clause (f) thereto:

“(f) any prohibition or restriction howsoever arising or created on the granting, conveying, creation or imposition of any Lien on the Equity Interests in the Excluded Subsidiary.”

2.6 Amendment to Section 9.16(a). Section 9.16(a) is hereby amended by adding the following subclause (iii) thereto:

“(iii) Swap Agreements in respect of carbon dioxide emission credits; provided that the aggregate amount that is owing but unpaid by the Borrower and its Subsidiaries under all such Swap Agreements shall not exceed $10,000,000 in the aggregate at any time.”

2.7 Amendment to Section 12.02(b)(vi). Section 12.02(b)(vi) is hereby amended by deleting the phrase “or change the definition of the terms “Domestic Subsidiary”, “Foreign Subsidiary”, “Material Domestic Subsidiary” or “Subsidiary”,” therefrom.

4

Section 3. Consent. Subject to the conditions precedent set forth in Section 4 of this Fourth Amendment and the ratification and affirmation set forth in Section 5.2 of this Fourth Amendment, the Administrative Agent and the Lenders (which such Lenders constitute all of the Lenders under the Credit Agreement) hereby consent to the LinnCo Transaction.

Section 4. Conditions Precedent. This Fourth Amendment shall become effective on the date (such date, the “Fourth Amendment Effective Date”), when each of the following conditions is satisfied (or waived in accordance with Section 12.02 of the Credit Agreement):

4.1 The Administrative Agent shall have received (a) all fees and other amounts due and payable on or prior to the Fourth Amendment Effective Date and all other fees the Borrower has agreed to pay in connection with this Fourth Amendment and (b) to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Original Agreement.

4.2 The Administrative Agent shall have received from all of the Lenders and the Borrower, counterparts (in such number as may be requested by the Administrative Agent) of this Fourth Amendment signed on behalf of such Person.

4.3 No Default shall have occurred and be continuing as of the date hereof, after giving effect to the terms of this Fourth Amendment.

The Administrative Agent is hereby authorized and directed to declare this Fourth Amendment to be effective when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 4 or the waiver of such conditions as permitted in Section 12.02 of the Credit Agreement. Such declaration shall be final, conclusive and binding upon all parties to the Agreement for all purposes.

Section 5. Miscellaneous.

5.1 Confirmation. The provisions of the Credit Agreement, as amended by this Fourth Amendment, shall remain in full force and effect following the effectiveness of this Fourth Amendment.

5.2 Ratification and Affirmation; Representations and Warranties. Each of the Borrower and the Guarantors hereby (a) acknowledges the terms of this Fourth Amendment; (b) ratifies and affirms its obligations under, and acknowledges its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect as expressly amended hereby and (c) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms of this Fourth Amendment:

(i) all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all material respects (except those which have a materiality qualifier, which shall be true and correct as so qualified), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct as of such specified earlier date,

5

(ii) no Default or Event of Default has occurred and is continuing, and

(iii) no event or events have occurred which individually or in the aggregate could reasonably be expected to have a Material Adverse Effect.

5.3 Loan Document. This Fourth Amendment is a Loan Document.

5.4 Counterparts. This Fourth Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Fourth Amendment by facsimile transmission shall be effective as delivery of a manually executed counterpart hereof.

5.5 NO ORAL AGREEMENT. THIS FOURTH AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES.

5.6 GOVERNING LAW. THIS FOURTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

5.7 Payment of Expenses. In accordance with Section 12.03 of the Credit Agreement, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable outof- pocket costs and reasonable expenses incurred in connection with this Fourth Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.

5.8 Severability. Any provision of this Fourth Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

5.9 Successors and Assigns. This Fourth Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

[SIGNATURES BEGIN NEXT PAGE]

6

IN WITNESS WHEREOF, the parties hereto have caused this Fourth Amendment to be duly executed as of the date first written above.

BORROWER:	LINN ENERGY, LLC
	By:	/s/ David B. Rottino
	Name:	David B. Rottino
	Title:	Senior Vice President of Finance, Business Development and Chief Accounting Officer

Signature Page to Fourth Amendment

GUARANTORS:	LINN ENERGY HOLDINGS, LLC
	LINN OPERATING, INC.
	MID-CONTINENT HOLDINGS I, LLC
	MID-CONTINENT HOLDINGS II, LLC
	MID-CONTINENT I, LLC
	MID-CONTINENT II, LLC
	LINN GAS MARKETING, LLC
	LINN EXPLORATION & PRODUCTION MICHIGAN LLC
	LINN MIDWEST ENERGY LLC
	By:	/s/ David B. Rottino
	Name:	David B. Rottino
	Title:	Senior Vice President of Finance, Business Development and Chief Accounting Officer

LINN EXPLORATION MIDCONTINENT, LLC
By:	Mid-Continent Holdings II, LLC, its sole member, as Member/Manager
By:	/s/ David B. Rottino
Name:	David B. Rottino
Title:	Senior Vice President of Finance, Business Development and Chief Accounting Officer

Signature Page to Fourth Amendment

LENDERS:	WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent and a Lender
	By:	/s/ Patrick J. Fults
	Name:	Patrick J. Fults
	Title:	Vice President

Signature Page to Fourth Amendment

ROYAL BANK OF CANADA
By:	/s/ Don J. McKinnerney
Name:	Don J. McKinnerney
Title:	Authorized Signatory

Signature Page to Fourth Amendment

BARCLAYS BANK PLC
By:	/s/ Vanessa A. Kurbatskiy
Name:	Vanessa A. Kurbatskiy
Title:	Vice President

Signature Page to Fourth Amendment

CITIBANK, N.A.
By:	/s/ John Miller
Name:	John Miller
Title:	Vice President

Signature Page to Fourth Amendment

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK
By:	/s/ Tom Byargeon
Name:	Tom Byargeon
Title:	Managing Director
By:	/s/ Sharada Manne
Name:	Sharada Manne
Title:	Managing Director

Signature Page to Fourth Amendment

CREDIT SUISSE AG, CAYMAN ISLAND BRANCH
By:	/s/ Doreen Barr
Name:	Doreen Barr
Title:	Director
By:	/s/ Michael Spaight
Name:	Michael Spaight
Title:	Associate

Signature Page to Fourth Amendment

THE ROYAL BANK OF SCOTLAND PLC
By:	/s/ Sanjay Remond
Name:	Sanjay Remond
Title:	Authorised Signatory

Signature Page to Fourth Amendment

THE BANK OF NOVA SCOTIA
By:	/s/ Terry Donovan
Name:	Terry Donovan
Title:	Managing Director

Signature Page to Fourth Amendment

BANK OF MONTREAL
By:	/s/ James V. Ducote
Name:	James V. Ducote
Title:	Director

Signature Page to Fourth Amendment

CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY
By:	/s/ Dominic D’Alessandro
Name:	Dominic D’Alessandro
Title:	Executive Director
By:	/s/ Trudy W. Nelson
Name:	Trudy W. Nelson
Title:	Executive Director

Signature Page to Fourth Amendment

UBS AG, STAMFORD BRANCH
By:	/s/ Irja R. Otsa
Name:	Irja R. Otsa
Title:	Associate Director
By:	/s/ Joselin Fernandes
Name:	Joselin Fernandes
Title:	Associate Director

Signature Page to Fourth Amendment

COMERICA BANK
By:	/s/ Justin Crawford
	Justin Crawford
	Senior Vice President

Signature Page to Fourth Amendment

ING CAPITAL LLC
By:	/s/ Juli Bieser
Name: Juli Bieser
Title: Director

Signature Page to Fourth Amendment

SOCIETE GENERALE
By:	/s/ Graeme Bullen
Name: Graeme Bullen
Title: Managing Director

Signature Page to Fourth Amendment

U.S. BANK NATIONAL ASSOCIATION
By:	/s/ Jonathan H. Lee
Name: Jonathan H. Lee
Title: Vice President

Signature Page to Fourth Amendment

ABN AMRO CAPITAL USA LLC
By:	/s/ David L. Montgomery
Name:	David L. Montgomery
Title:	Director
By:	/s/ Darrell Holley
Name:	Darrell Holley
Title:	Managing Director

Signature Page to Fourth Amendment

COMPASS BANK
By:	/s/ Kathleen J. Bowen
Name: Kathleen J. Bowen
Title: Senior Vice President

Signature Page to Fourth Amendment

DNB BANK ASA, GRAND CAYMAN
BRANCH (f/k/a DnB NOR Bank ASA)
By:	/s/ Cathleen Buckley
Name:	Cathleen Buckley
Title:	Senior Vice President
By:	/s/ Colleen Durkin
Name:	Colleen Durkin
Title:	Senior Vice President
	Shipping, Offshore & Logistics

Signature Page to Fourth Amendment

UNION BANK, N.A.
By:	/s/ Stephen W. Warfel
Name: Stephen W. Warfel
Title: Senior Vice President

Signature Page to Fourth Amendment

CAPITAL ONE, N.A.
By:	/s/ Matthew L. Molero
Name: Matthew L. Molero
Title: Vice President

Signature Page to Fourth Amendment

SUNTRUST BANK
By:	/s/ Yann Pirio
Name: Yann Pirio
Title: Director

Signature Page to Fourth Amendment

BANK OF AMERICA, N.A.
By:	/s/ Joseph Scott
Name:	Joseph Scott
Title:	Director

Signature Page to Fourth Amendment

JPMORGAN CHASE BANK, N.A.
By:	/s/ Michael A. Kamauf
Name:	Michael A. Kamauf
Title:	Authorized Officer

Signature Page to Fourth Amendment

DEUTSCHE BANK TRUST COMPANY AMERICAS
By:	/s/ Michael Getz
Name:	Michael Getz
Title:	Vice President
By:	/s/ Marcus M. Tarkington
Name:	Marcus M. Tarkington
Title:	Director

Signature Page to Fourth Amendment

GOLDMAN SACHS BANK USA
By:	/s/ Michelle Latzoni
Name:	Michelle Latzoni
Title:	Authorized Signatory

Signature Page to Fourth Amendment

MACQUARIE BANK LIMITED
By:	/s/ Christian Coles
Name:	Christian Coles
Title:	Division Director
By:	/s/ Joel Outlaw
Name:	Joel Outlaw
Title:	Associate Director Legal Risk Management
	(Macquarie POA Ref: # 594/10
	dated 25 November 2010)

Signature Page to Fourth Amendment

MORGAN STANLEY BANK, N.A.
By:	/s/ Scott Taylor
Name:	Scott Taylor
Title:	Authorized Signatory

Signature Page to Fourth Amendment

BP ENERGY COMPANY
By:	/s/ Sharon Weintraub
Name:	Sharon Weintraub
Title:	Head of Mid-Office Control

Signature Page to Fourth Amendment

BNP PARIBAS
By:	/s/ David Dodd
Name:	David Dodd
Title:	Managing Director
By:	/s/ Sriram Chandrasekaran
Name:	Sriram Chandrasekaran
Title:	Vice President

Signature Page to Fourth Amendment

BRANCH BANKING AND TRUST COMPANY
By:	/s/ Parul June
Name:	Parul June
Title:	Vice President

Signature Page to Fourth Amendment

SUMITOMO MITSUI BANKING CORPORATION
By:	/s/ Shuji Yabe
Name:	Shuji Yabe
Title:	Managing Director

Signature Page to Fourth Amendment

WHITNEY BANK
By:	/s/ Liana Tchernysheya
	Liana Tchernysheya
	Senior Vice President

Signature Page to Fourth Amendment

AMEGY BANK NATIONAL ASSOCIATION
By:	/s/ William B. Robinson
Name:	William B. Robinson
Title:	Vice President

Signature Page to Fourth Amendment

ASSOCIATED BANK, N.A.
By:	/s/ Farhan Iqbal
Name:	Farhan Iqbal
Title:	Vice President

Signature Page to Fourth Amendment

KEYBANK NATIONAL ASSOCIATION
By:	/s/ Chulley Bogle
Name:	Chulley Bogle
Title:	Vice President

Signature Page to Fourth Amendment

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Tax Benefit Expense from Continuing Operations

Income tax benefit (expense) from continuing operations consisted of the following:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Current taxes:
Federal	$	(4,551	)	$	(65	)	$	(1,063	)
State		(605	)		(1,088	)		(678	)
Deferred taxes:
Federal		1,148			(2,862	)		5,307
State		(1,458	)		(226	)		655
	$	(5,466	)	$	(4,241	)	$	4,221

Effective Income Tax Rate Reconciliation

Income tax benefit (expense) differed from amounts computed by applying the federal income tax rate of 35% to pre-tax income (loss) from continuing operations as a result of the following:

	Year Ended December 31,
	2011			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%
State, net of federal tax benefit		0.5			(1.2	)		—
Loss excluded from nontaxable entities		(34.4	)		(37.5	)		(34.3	)
Other items		0.1			(0.1	)		0.7
Effective rate		1.2	%		(3.8	)%		1.4	%

Components of Deferred tax Assets and Liabilities

Significant components of the deferred tax assets and liabilities were as follows:

	December 31,
	2011			2010
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	159		$	717
Unit-based compensation		9,146			6,234
Other		3,606			3,513
Valuation allowance		—			(217	)
Total deferred tax assets		12,911			10,247
Deferred tax liabilities:
Other accruals		—			(2,755	)
Property and equipment principally due to differences in depreciation		(8,226	)		(4,323	)
Other		(1,646	)		179
Total deferred tax liabilities		(9,872	)		(6,899	)
Net deferred tax assets	$	3,039		$	3,348

Net Deferred Tax Assets and Liabilities Classified in Consolidated Balance Sheets

Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:

	December 31,
	2011			2010
	(in thousands)
Deferred tax assets	$	8,279		$	5,265
Deferred tax liabilities		(589	)		(3,105	)
Other current assets	$	7,690		$	2,160
Deferred tax assets	$	4,632		$	4,982
Deferred tax liabilities		(9,283	)		(3,794	)
Other noncurrent assets (liabilities)	$	(4,651	)	$	1,188

XML

Debt Outstanding (Parenthetical) (Detail) (Line of Credit, Credit Facility)	Jun. 30, 2012	Dec. 31, 2011
Line of Credit | Credit Facility
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End (in hundredths)	2.02%	2.57%	[1]

[1] Represents variable interest rate for the Credit Facility and effective interest rates for the senior notes.

XML

Unit-Based Compensation and Other Benefit Plans - Additional Information (Detail) (USD $)	12 Months Ended								1 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Unit Options	Dec. 31, 2010 Unit Options	Dec. 31, 2009 Unit Options	Dec. 31, 2011 Unit Options Nonemployee	Dec. 31, 2007 Unit Options Nonemployee	Jan. 31, 2012 Restricted Units	Dec. 31, 2011 Restricted Units Year	Dec. 31, 2010 Restricted Units	Dec. 31, 2009 Restricted Units	Dec. 31, 2011 Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vesting period (in years)				3 years
Unit options contractual life (in years)				10 years
Number of shares available for grant (in units)	5,200,000									12,200,000
Phantom units issued and outstanding (in units)													36,784
Units authorized for issuance (in units)	1,400,000
Granted (in dollars per unit)	$ 38.54	$ 25.89	$ 16.11
Unrecognized compensation cost				$ 4,000						$ 38,000,000
Unrecognized compensation cost recognition period (in years)										1.5
Fair value of units vested										13,000,000	14,000,000	11,000,000
Restricted units granted to employees (in units)	1,110,502								913,663
Weighted average grant date fair value of options granted (in dollars per unit)						$ 0.55
Intrinsic value of options exercised				5,000,000	2,000,000	124,000
Proceeds from exercise of stock options				7,000,000
Intrinsic value of exercisable unit options				19,000,000
Intrinsic value of outstanding unit options	22,000,000
Fair value of options vested				500,000	1,000,000	2,000,000
Unit warrants granted (in units)								150,000
Exercise price of unit warrants (in dollars per unit)							$ 25.50
Unit warrants contractual term (in years)							10
Entity's matching contribution (in hundredths)	100.00%	100.00%	100.00%
Participant's eligible contribution, (in hundredths)	6.00%	6.00%	4.00%
Contribution to 401 (k) defined contribution plan	$ 4,000,000	$ 3,000,000	$ 2,000,000

XML

Income Tax Benefit Expense from Continuing Operations (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current taxes [Abstract]
Federal					$ (4,551)	$ (65)	$ (1,063)
State					(605)	(1,088)	(678)
Deferred taxes [Abstract]
Federal					1,148	(2,862)	5,307
State					(1,458)	(226)	655
Income tax benefit (expense)	$ (512)	$ (1,670)	$ (9,430)	$ (5,868)	$ (5,466)	$ (4,241)	$ 4,221

XML

Debt - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended			3 Months Ended			12 Months Ended				6 Months Ended											3 Months Ended		3 Months Ended	12 Months Ended			6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended		1 Months Ended	6 Months Ended	12 Months Ended		1 Months Ended		6 Months Ended	12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Jun. 30, 2012 Line of Credit Credit Facility		Mar. 31, 2012 Line of Credit Credit Facility	Dec. 31, 2011 Line of Credit Credit Facility		Feb. 29, 2012 Line of Credit Credit Facility	Oct. 31, 2011 Line of Credit Credit Facility	Jun. 30, 2012 Line of Credit Credit Facility Minimum	Jun. 30, 2012 Line of Credit Credit Facility Maximum	Jun. 30, 2012 Line of Credit Credit Facility LIBOR Minimum	Dec. 31, 2011 Line of Credit Credit Facility LIBOR Minimum	Jun. 30, 2012 Line of Credit Credit Facility LIBOR Maximum	Dec. 31, 2011 Line of Credit Credit Facility LIBOR Maximum	Jun. 30, 2012 Line of Credit Credit Facility ABR Minimum	Dec. 31, 2011 Line of Credit Credit Facility ABR Minimum	Jun. 30, 2012 Line of Credit Credit Facility ABR Maximum	Dec. 31, 2011 Line of Credit Credit Facility ABR Maximum	Jul. 31, 2012 Line of Credit Credit Facility Line Of Credit Facility Increase In Maximum Borrowing Capacity	Mar. 31, 2012 Subordinated Debt Senior Notes Due November 2019	Jun. 30, 2012 Subordinated Debt Senior Notes Due November 2019	Jun. 30, 2011 Subordinated Debt Senior Notes Due May 2019	Dec. 31, 2011 Subordinated Debt Senior Notes Due May 2019	Jun. 30, 2012 Subordinated Debt Senior Notes Due May 2019	Jun. 30, 2012 Subordinated Debt Senior Notes Due May 2019 Maximum	Jun. 30, 2012 Subordinated Debt Senior Notes Due 2020	Dec. 31, 2011 Subordinated Debt Senior Notes Due 2020	Dec. 31, 2010 Subordinated Debt Senior Notes Due 2020	Jun. 30, 2012 Subordinated Debt Senior Notes Due 2021	Dec. 31, 2011 Subordinated Debt Senior Notes Due 2021	Dec. 31, 2010 Subordinated Debt Senior Notes Due 2021	Jun. 30, 2011 Subordinated Debt Senior Notes Due 2017	Jun. 30, 2012 Subordinated Debt Senior Notes Due 2017	Dec. 31, 2011 Subordinated Debt Senior Notes Due 2017	Dec. 31, 2010 Subordinated Debt Senior Notes Due 2017	Dec. 31, 2011 Subordinated Debt Senior Notes Due 2018	Jun. 30, 2011 Subordinated Debt Senior Notes Due 2018	Jun. 30, 2012 Subordinated Debt Senior Notes Due 2018	Dec. 31, 2011 Subordinated Debt Senior Notes Due 2018	Dec. 31, 2010 Subordinated Debt Senior Notes Due 2018
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity													$ 2,000,000,000	$ 1,500,000,000											$ 3,000,000,000
Line of Credit Facility, redetermined borrowing base										3,500,000,000				3,000,000,000
Line of Credit Facility, Remaining Borrowing Capacity								646,000,000			556,000,000
Outstanding letters of credit that reduce the credit facility availability								4,000,000			4,000,000
Line Of Credit Facility Financing Fees And Expense Incurred								5,000,000			4,000,000
The percentage of properties that the company is required to maintain mortgages on (in hundredths)								80.00%			80.00%
Debt Instrument, Basis Spread on Variable Rate																	1.50%	1.75%	2.50%	2.75%	0.50%	0.75%	1.50%	1.75%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage											0.50%				0.375%	0.50%
Debt Instrument, Issuance Date																										2012-03-02		2011-05-13	2011-05-13				2010-04-06			2010-10-13
Debt Instrument, Face Amount																										1,800,000,000			750,000,000	750,000,000		1,300,000,000	1,300,000,000		1,000,000,000	1,000,000,000			250,000,000	250,000,000		256,000,000		256,000,000	256,000,000
Debt Instrument, Interest Rate, Stated Percentage																										6.25%			6.50%	6.50%		8.625%	8.625%		7.75%	7.75%			11.75%	11.75%		9.875%		9.875%	9.875%
Debt Instrument, Maturity Date								Apr. 06, 2017		Apr. 06, 2016																Nov. 01, 2019		May 15, 2019	May 15, 2019			Apr. 15, 2020	Apr. 15, 2020		Feb. 01, 2021	Feb. 01, 2021			May 15, 2017	May 15, 2017				Jun. 01, 2018	Jun. 01, 2018
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)																										99.989%			99.232%
Net proceeds received																										1,770,000,000			729,000,000
Financing fees and expenses incurred related to the issuance of long-term debt																										29,000,000			15,000,000
Unamortized discount																										198,000			6,000,000
Maximum percentage of 2019 Senior Notes that can be redeemed on or before May 15, 2014 (in hundredths)																													35.00%
Redemption price, stated as a percentage of the face amount, for 2019 Senior Notes redeemed on or before May 15, 2014 (in hundredths)																													106.50%
Redemption price, stated as a percentage of the face amount, for 2019 Senior Notes redeemed on or after May 15, 2015, but on or before December 31, 2015 (in hundredths)																													103.25%
Redemption price of 2019 Senior Notes if there is a change of control (in hundredths)																													101.00%
Number Of Days For Effective Registration Statement																										400 days			400 days
Long-term Debt, Gross								1,150,000,000	[1]		940,000,000	[1]															1,800,000,000		750,000,000	750,000,000		1,300,000,000	1,300,000,000	1,300,000,000	1,000,000,000	1,000,000,000	1,000,000,000		41,000,000	41,000,000	250,000,000	14,000,000		14,000,000	14,000,000	256,000,000
Debt instrument redemption amount																																								87,000,000					90,000,000
Debt instrument principal outstanding after redemptions																																								163,000,000		166,000,000			166,000,000
Debt instrument initial tender offer total consideration																																								1,212.50					1,172.50
Increment amount of senior notes principal tendered																																								1,000					1,000
Tender offer consent payment																																								30.00					30.00
Debt instrument secondary tender offer total consideration																																								1,182.50					1,142.50
Debt instrument total amount tendered																																								105,000,000					126,000,000
Debt instrument percentage tendered																																								65.00%					76.00%
Debt instrument repurchase amount																																						17,000,000				2,000,000	24,000,000		2,000,000
Debt instrument repurchase percentage																																						29.00%				9.00%	61.00%
Loss on extinguishment of debt	0	(9,810,000)	0	(94,372,000)	(94,612,000)	0	0
Line Of Credit Facility Swap Agreement Capacity Restriction								200,000,000
Line Of Credit Facility Collateral Coverage Ratio								2.5
Maximum Percentage Of November 2019 Senior Notes Redeemable On Before 2015																										35.00%
Redemption Price Percentage For Redemption On Before 2015																										106.25%
Redemption Price Percentage For Redemption After November 2015																										103.125%
Redemption Price Percentage Of Senior Notes If Change Of Control																										101.00%
Additional Interest Due To Late Registration																															$ 500,000

[1] Variable interest rates of 2.02% and 2.57% at June 30, 2012, and December 31, 2011, respectively.

XML

Acquisitions - Additional Information (Detail) (USD $)			1 Months Ended			6 Months Ended	1 Months Ended					1 Months Ended	12 Months Ended	1 Months Ended		12 Months Ended	1 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	May 01, 2012 Business Acquisition East Texas	Apr. 30, 2012 Business Acquisition Anadarko	Apr. 03, 2012 Business Acquisition Anadarko	Jun. 30, 2012 Business Acquisition Anadarko	Jun. 21, 2012 Business Acquisition BP	Mar. 30, 2012 Business Acquisition BP	Jun. 30, 2012 Business Acquisition BP	Jun. 30, 2012 Business Acquisition Various	Dec. 31, 2011 Business Acquisition Various	Jun. 01, 2011 Business Acquisition Panther	Dec. 31, 2011 Business Acquisition Panther	May 11, 2011 Business Acquisition Williston Basin	Apr. 05, 2011 Business Acquisition SandRidge	Dec. 31, 2011 Business Acquisition SandRidge	Mar. 31, 2011 Business Acquisition Concho	Dec. 31, 2011 Business Acquisition Concho
Business Acquisition [Line Items]
Total consideration transferred			$ 168,000,000					$ 1,170,000,000		$ 67,000,000	$ 38,000,000	$ 224,000,000	$ 223,000,000	$ 153,000,000	$ 239,000,000	$ 239,000,000	$ 192,000,000	$ 194,000,000
Acquisition closing date			May 1, 2012	April 3, 2012				March 30, 2012				June 1, 2011	June 1, 2011	May 2, 2011 and May 11, 2011	April 1, 2011 and April 5, 2011	April 1, 2011, and April 5, 2011	March 31, 2011	March 31, 2011
Joint venture interest acquired					23.00%
Future funding of joint venture agreement					400,000,000
Business acquisitions - Net assets acquired	1,402,192,000	1,501,483,000			392,000,000
Imputed discount on future funding of joint venture					8,000,000
Future funding commitment of joint venture consideration transferred						54,000,000
Business acquisitions - current liabilities assumed					195,000,000
Business acquisitions - non-current liabilities assumed	196,600,000				197,000,000
Execution date of acquisition purchase and sale agreement							2012-06-21
Acquisition contract price							1,030,000,000
Business acquisition amount of cash deposit									308,000,000
Amount of cash paid to acquire the entity																	194,000,000	196,000,000
Amount of receivable recorded																	$ 2,000,000	$ 2,000,000

XML

Unitholders Capital - Additional Information (Detail) (USD $)	1 Months Ended											3 Months Ended		12 Months Ended
	Feb. 29, 2012	Jan. 27, 2012	Jan. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Aug. 31, 2011	Mar. 31, 2011	Dec. 31, 2010	Mar. 31, 2010	Oct. 31, 2009	May 31, 2009	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008	Apr. 24, 2012	Jul. 24, 2012 Dividend Declared
Equity [Line Items]
Date of equity distribution agreement						Aug. 23, 2011
Equity distribution agreement maximum value						$ 500,000,000
Equity distribution agreement origination expense						423,000
Equity distribution agreement remaining balance			411,000,000	470,000,000								411,000,000		470,000,000
Equity distribution agreement units sold			1,539,651	772,104	16,060
Equity distribution agreement price per unit sold			38.02	38.03	38.25
Equity distribution agreement net proceeds			57,000,000	29,000,000	602,000
Equity distribution agreement commission fees			1,000,000	587,000	12,000
Equity distribution agreement professional service expenses														139,000
Public offering units sold			19,550,000				16,726,067	11,500,000	17,250,000	8,625,000	6,325,000
Public offering price per unit			35.95				38.80	35.92	25.00	21.90	16.25
Public offering price per unit, net of underwriting discount			34.512				37.248	34.48	24.00	21.024	15.60
Public offering net proceeds			674,000,000				623,000,000	396,000,000	414,000,000	181,000,000	98,000,000				396,000,000
Public offering underwriting discount and offering expenses			28,000,000				26,000,000	17,000,000	17,000,000	8,000,000	4,000,000
Authorized repurchase value of units																	100,000,000
Average unit price of units repurchased (in dollars per unit)														$ 32.76	$ 23.79	$ 12.99
Total cost of units repurchased														17,000,000	12,000,000	2,000,000
Units repurchased during the period (in units)														529,734	486,700	123,800
Remaining balance of units repurchase program														56,000,000
Units purchased related to minimum withholding taxes due under equity compensation plan (in units)														0	9,055	63,031
Total cost of units purchased related to minimum withholding taxes due under equity compensation plan															300,000	1,000,000
Per unit cash dividend paid (in usd per unit)		$ 0.69										$ 0.725	$ 0.690
Distribution paid during period	138,000,000
Equity Distribution Agreement Commissions And Professional Service Expenses			2,000,000
Equity distribution agreement units issued and sold date			Jan. 31, 2012
Public Offering New Units Sold Date			Jan. 19, 2012				Apr. 30, 2011
Percentage increase in quarterly distribution amount																		5.00%
Per unit cash dividend declared (in usd per unit)																			$ 0.725
Estimated distribution payable in subsequent period																			$ 145,000,000

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Derivatives (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Commodity Derivatives

The following table summarizes derivative positions for the periods indicated as of June 30, 2012:

	July 1 – December 31, 2012			2013			2014			2015			2016			2017
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		43,910			87,290			97,401			118,041			121,841			120,122
Average price ($/MMBtu)	$	5.16		$	5.22		$	5.25		$	5.19		$	4.20		$	4.26
Puts:(1)
Hedged volume (MMMBtu)		38,894			86,198			79,628			71,854			76,269			66,886
Average price ($/MMBtu)	$	5.41		$	5.37		$	5.00		$	5.00		$	5.00		$	4.88
Total:
Hedged volume (MMMBtu)		82,804			173,488			177,029			189,895			198,110			187,008
Average price ($/MMBtu)	$	5.28		$	5.29		$	5.14		$	5.12		$	4.51		$	4.48
Oil positions:
Fixed price swaps:(2)
Hedged volume (MBbls)		4,730			11,871			11,903			11,599			11,464			4,755
Average price ($/Bbl)	$	96.72		$	94.97		$	92.92		$	96.23		$	90.56		$	89.02
Puts:
Hedged volume (MBbls)		1,251			3,105			3,960			3,426			3,271			384
Average price ($/Bbl)	$	99.32		$	97.86		$	91.30		$	90.00		$	90.00		$	90.00
Total:
Hedged volume (MBbls)		5,981			14,976			15,863			15,025			14,735			5,139
Average price ($/Bbl)	$	97.26		$	95.57		$	92.52		$	94.81		$	90.44		$	89.10
Natural gas basis differential positions:(3)
Panhandle basis swaps:
Hedged volume (MMMBtu)		37,535			77,800			79,388			87,162			19,764			—
Hedged differential ($/MMBtu)	$	(0.55	)	$	(0.56	)	$	(0.33	)	$	(0.33	)	$	(0.31	)	$	—
NWPL—Rockies basis swaps:
Hedge volume (MMMBtu)		14,122			34,785			36,026			38,362			39,199			—
Hedge differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	—
MichCon basis swaps:
Hedged volume (MMMBtu)		4,894			9,600			9,490			9,344			—			—
Hedged differential ($/MMBtu)	$	0.12		$	0.10		$	0.08		$	0.06		$	—		$	—
Houston Ship Channel basis swaps:
Hedged volume (MMMBtu)		3,146			5,731			5,256			4,891			4,575			—
Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	—
Permian basis swaps:
Hedged volume (MMMBtu)		2,282			4,636			4,891			5,074			—			—
Hedged differential ($/MMBtu)	$	(0.19	)	$	(0.20	)	$	(0.21	)	$	(0.21	)	$	—		$	—
Oil timing differential positions:
Trade month roll swaps:(4)
Hedged volume (MBbls)		3,284			6,944			7,254			7,251			7,446			6,486
Hedged differential ($/Bbl)	$	0.21		$	0.22		$	0.22		$	0.24		$	0.25		$	0.25

(1) Includes certain outstanding natural gas puts of approximately 5,329 MMMBtu for the period July 1, 2012, through December 31, 2012, 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.

(2) Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

(3) Settle on the respective pricing index to hedge basis differential associated with natural gas production.

(4) The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

The following table summarizes open positions as of December 31, 2011, and represents, as of such date, derivatives in place through December 31, 2016, on annual production volumes:

	2012			2013			2014			2015			2016
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		56,730			64,367			73,456			82,490			2,745
Average price ($/MMBtu)	$	5.85		$	5.69		$	5.69		$	5.75		$	5.00
Puts:
Hedged volume (MMMBtu)		38,357			37,340			30,660			32,850			—
Average price ($/MMBtu)	$	5.83		$	5.85		$	5.00		$	5.00		$	—
Total:
Hedged volume (MMMBtu)		95,087			101,707			104,116			115,340			2,745
Average price ($/MMBtu)	$	5.84		$	5.75		$	5.49		$	5.54		$	5.00
Oil positions:
Fixed price swaps:(1)
Hedged volume (MBbls)		8,171			9,033			9,034			9,581			—
Average price ($/Bbl)	$	97.37		$	98.05		$	95.39		$	98.25		$	—
Puts:
Hedged volume (MBbls)		2,196			2,300			—			—			—
Average price ($/Bbl)	$	100.00		$	100.00		$	—		$	—		$	—
Total:
Hedged volume (MBbls)		10,367			11,333			9,034			9,581			—
Average price ($/Bbl)	$	97.93		$	98.44		$	95.39		$	98.25		$	—
Natural gas basis differential positions:
PEPL basis swaps:(2)
Hedged volume (MMMBtu)		37,735			38,854			42,194			42,194			—
Hedged differential ($/MMBtu)	$	(0.89	)	$	(0.89	)	$	(0.39	)	$	(0.39	)	$	—
Oil timing differential positions:
Trade month roll swaps:(3)
Hedged volume (MBbls)		5,982			6,315			6,315			840			—
Hedged differential ($/Bbl)	$	0.21		$	0.21		$	0.21		$	0.17		$	—

(1) As presented in the table above, the Company has certain outstanding fixed price oil swaps on 14,750 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2016, December 31, 2017, and December 31, 2018, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

(2) Settle on the Panhandle Eastern Pipeline (“PEPL”) spot price of natural gas to hedge basis differential associated with natural gas production in the Mid-Continent Deep and Mid-Continent Shallow regions.

(3) The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent Deep, Mid-Continent Shallow and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

Balance Sheet Presentation

The following summarizes the fair value of derivatives outstanding on a gross basis:

	June 30, 2012		December 31, 2011
	(in thousands)
Assets:
Commodity derivatives	$	1,730,071	$	880,175
Liabilities:
Commodity derivatives	$	319,935	$	320,835

The following summarizes the fair value of derivatives outstanding on a gross basis:

	December 31,
	2011		2010
	(in thousands)
Assets:
Commodity derivatives	$	880,175	$	637,836
Liabilities:
Commodity derivatives	$	320,835	$	398,902

Gains and Losses on Derivatives

The following presents the Company’s reported gains and losses on derivative instruments:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Realized gains:
Commodity derivatives	$	117,740	$	42,081	$	172,995	$	97,890
Recovery of bankruptcy claim (see Note 10)		18,277		—		18,277		—
		136,017		42,081		191,272		97,890
Unrealized gains (losses):
Commodity derivatives		303,630		163,434		250,406		(261,851	)
Total gains (losses):
Total	$	439,647	$	205,515	$	441,678	$	(163,961	)

The following presents the Company’s reported gains and losses on derivative instruments:

	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	230,237	$	307,587		$	400,968
Interest rate swaps		—		(8,021	)		(42,881	)
Canceled derivatives		26,752		(123,865	)		48,977
	$	256,989	$	175,701		$	407,064
Unrealized gains (losses):
Commodity derivatives	$	192,951	$	(232,376	)	$	(591,379	)
Interest rate swaps		—		63,978			16,588
	$	192,951	$	(168,398	)	$	(574,791	)
Total gains (losses):
Commodity derivatives	$	449,940	$	75,211		$	(141,374	)
Interest rate swaps		—		(67,908	)		(26,353	)
	$	449,940	$	7,303		$	(167,727	)

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Oil and Natural Gas Properties (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Proved properties:
Leasehold acquisition	$ 7,460,077	$ 6,040,239
Development	2,019,012	1,484,486
Unproved properties	516,659	310,925
Oil and natural gas properties (successful efforts method)	9,995,748	7,835,650	5,664,503
Less accumulated depletion and amortization	(1,426,132)	(1,033,617)	(719,035)
Oil and natural gas properties, successful efforts method, net	$ 8,569,616	$ 6,802,033	$ 4,945,468

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Components of Deferred tax Assets and Liabilities (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Deferred tax assets [Abstract]
Net operating loss carryforwards	$ 159	$ 717
Unit-based compensation	9,146	6,234
Other	3,606	3,513
Valuation allowance		(217)
Total deferred tax assets	12,911	10,247
Deferred tax liabilities [Abstract]
Other accruals		(2,755)
Property and equipment principally due to differences in depreciation	(8,226)	(4,323)
Other	(1,646)	179
Total deferred tax liabilities	(9,872)	(6,899)
Net deferred tax assets	$ 3,039	$ 3,348

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Commodity Derivatives (Parenthetical) (Detail)	Jun. 30, 2012 Mbbl	Dec. 31, 2011 Mbbl
Oil Derivative Instruments | 2012
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	5,981	10,367
Weighted Average Fixed Price (in usd per energy unit)	97.26	97.93
Oil Derivative Instruments | 2013
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	14,976	11,333
Weighted Average Fixed Price (in usd per energy unit)	95.57	98.44
Oil Derivative Instruments | 2014
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	15,863	9,034
Weighted Average Fixed Price (in usd per energy unit)	92.52	95.39
Oil Derivative Instruments | 2015
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	15,025	9,581
Weighted Average Fixed Price (in usd per energy unit)	94.81	98.25
Oil Derivative Instruments | 2016
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	14,735
Weighted Average Fixed Price (in usd per energy unit)	90.44
Oil Derivative Instruments | 2017
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	5,139
Weighted Average Fixed Price (in usd per energy unit)	89.10
Puts | Oil Derivative Instruments | 2012
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	1,251	2,196
Puts | Oil Derivative Instruments | 2013
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,105	2,300
Puts | Oil Derivative Instruments | 2014
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,960
Puts | Oil Derivative Instruments | 2015
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,426
Puts | Oil Derivative Instruments | 2016
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,271
Puts | Oil Derivative Instruments | 2017
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	384
Puts | Natural Gas Liquid Commodity Contract | 2012
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	5,329
Puts | Natural Gas Liquid Commodity Contract | 2013
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	10,570
Puts | Natural Gas Liquid Commodity Contract | 2014
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	10,570
Puts | Natural Gas Liquid Commodity Contract | 2015
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	10,570
Puts | Natural Gas Liquid Commodity Contract | 2016
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	10,599
Extendible Fixed Price Swaps | Oil Derivative Instruments | 2016
Derivative [Line Items]
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)		14,750
Weighted Average Fixed Price (in usd per energy unit)		100.00
Extendible Fixed Price Swaps | Oil Derivative Instruments | 2017
Derivative [Line Items]
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384	14,750
Weighted Average Fixed Price (in usd per energy unit)	100.00	100.00
Extendible Fixed Price Swaps | Oil Derivative Instruments | 2018
Derivative [Line Items]
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384	14,750
Weighted Average Fixed Price (in usd per energy unit)	100.00	100.00
Extendible Fixed Price Swaps | Oil Derivative Instruments | 2019
Derivative [Line Items]
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384
Weighted Average Fixed Price (in usd per energy unit)	90.00

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Supplemental Disclosures to Condensed Consolidated Statements of Cash Flows (Detail) (USD $) In Thousands, unless otherwise specified	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Business Acquisition [Line Items]
Cash payments for interest, net of amounts capitalized	$ 128,617	$ 124,173	$ 247,217	$ 128,807	$ 73,861
Cash payments for income taxes	306	476	487	1,797	1,282
Noncash investing activities - liabilities assumed
Fair value of assets acquired	1,841,027	850,313	1,523,466	1,375,010	117,717
Cash paid, net of cash acquired	(1,455,433)	(847,780)	(1,500,193)	(1,351,033)	(115,285)
Receivable from seller	772	5,855	3,557	9,976	636
Payables to sellers	(422)	(5,241)	(4,847)
Liabilities assumed	$ 385,944	$ 3,147	$ 21,983	$ 33,953	$ 3,068

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Unit-Based Compensation - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended	6 Months Ended
	Dec. 31, 2011	Jun. 30, 2012 Share-based compensation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted units granted to employees (in units)	1,110,502	953,668
Aggregate fair value of restricted units issued to employees		$ 35
Vesting period of restricted units granted to employees		3 years

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Supplemental Disclosures to Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Financial Information [Line Items]
Restricted cash	$ 4	$ 4	$ 3
Net Outstanding Checks	13	54
Business Acquisition BP
Supplemental Financial Information [Line Items]
Business acquisition amount of cash deposit	$ 308

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Income Taxes - Additional Information (Detail) (Federal, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Federal
Income Tax [Line Items]
Net operating loss carryforwards	$ 8
Net operating loss carryforwards, expiration dates	2031

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Acquisitions

6 Months Ended

Jun. 30, 2012

Acquisitions

Note 2—Acquisitions

Acquisitions—2012

On May 1, 2012, the Company completed the acquisition of certain oil and natural gas properties located in east Texas. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid approximately $168 million in total consideration for these properties. The transaction was financed primarily with borrowings under the Company’s Credit Facility, as defined in Note 6.

On April 3, 2012, the Company entered into a joint-venture agreement (“Agreement”) with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) whereby the Company will participate as a partner in the CO2 enhanced oil recovery development of the Salt Creek field, located in the Powder River Basin of Wyoming. Anadarko assigned the Company 23% of its interest in the field in exchange for future funding of $400 million of Anadarko’s development costs. The results of operations of these properties have been included in the condensed consolidated financial statements since the Agreement date. The Company assigned approximately $392 million to the net assets acquired as of the Agreement date, which reflects an imputed discount of approximately $8 million on the future funding of this transaction. As of June 30, 2012, the Company has paid approximately $54 million towards the future funding commitment.

On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin in Kansas from BP America Production Company (“BP”). The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid approximately $1.17 billion in total consideration for these properties. The transaction was financed primarily with proceeds from the March 2012 debt offering, as described below.

During the six months ended June 30, 2012, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition dates. The Company, in the aggregate, paid approximately $67 million in total consideration for these properties.

These acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):

Assets:
Current	$	7,358
Noncurrent		208,423
Oil and natural gas properties		1,625,246
Total assets acquired	$	1,841,027
Liabilities:
Current	$	208,139
Asset retirement obligations		34,096
Noncurrent		196,600
Total liabilities assumed	$	438,835
Net assets acquired	$	1,402,192

Current assets include receivables and inventory and noncurrent assets include other property and equipment. Current liabilities include payables, ad valorem taxes payable and environmental liabilities. Current liabilities and noncurrent liabilities, as of the Agreement date, consist of payables of approximately $195 million and $197 million, respectively, related to the future funding commitment associated with the Anadarko transaction discussed above. As of June 30, 2012, the Company has paid approximately $54 million towards this commitment.

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

The revenues and expenses related to certain properties acquired from BP, Plains Exploration & Production Company (“Plains”), Panther Energy Company, LLC and Red Willow Mid-Continent, LLC (collectively referred to as “Panther”), SandRidge Exploration and Production, LLC (“SandRidge”) and an affiliate of Concho Resources Inc. (“Concho”) are included in the condensed consolidated results of operations of the Company as of March 30, 2012, December 15, 2011, June 1, 2011, April 1, 2011, and March 31, 2011, respectively. The following unaudited pro forma financial information presents a summary of the Company’s condensed consolidated results of operations for the six months ended June 30, 2012, and three months and six months ended June 30, 2011, assuming the acquisition from BP had been completed as of January 1, 2011, and the acquisitions from Plains, Panther, SandRidge and Concho had been completed as of January 1, 2010, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of these dates.

	Three Months Ended June 30,		Six Months Ended June 30,
	2011		2012		2011
	(in thousands, except per unit amounts)
Total revenues and other	$	647,633	$	1,211,569	$	640,027
Total operating expenses	$	268,273	$	779,199	$	514,965
Net income (loss)	$	276,393	$	220,419	$	(159,406	)
Net income (loss) per unit:
Basic	$	1.56	$	1.11	$	(0.94	)
Diluted	$	1.56	$	1.11	$	(0.94	)

Acquisition—Pending

On June 21, 2012, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Green River Basin area of southwest Wyoming from BP for a contract price of approximately $1.03 billion. The Company paid a deposit of approximately $308 million in June 2012, which is reported in “other noncurrent assets” on the condensed consolidated balance sheet at June 30, 2012. The Company anticipates the acquisition will close on or before July 31, 2012, subject to closing conditions, and will be financed with borrowings under its Credit Facility, as defined in Note 6.

Acquisition—2011

On June 1, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Cleveland play, located in the Texas Panhandle, from Panther. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid approximately $224 million in total consideration for these properties. The transaction was financed primarily with proceeds from the Company’s May 2011 debt offering.

On May 2, 2011 and May 11, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Williston Basin. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition dates. The Company paid approximately $153 million in total consideration for these acquisitions. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On April 1, 2011 and April 5, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin, including properties from SandRidge. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition dates. The Company paid approximately $239 million in total consideration for these acquisitions. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Williston Basin from Concho. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid $194 million in cash and recorded a receivable from Concho of $2 million, resulting in total consideration for the acquisition of approximately $192 million. The transaction was financed primarily with proceeds from the Company’s March 2011 public offering of units, as described below.

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Restricted/Unrestricted Nonvested Units (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Restricted/Unrestricted Nonvested Units [Roll Forward]
Nonvested units, beginning (in units)	1,451,556
Granted (in units)	1,110,502
Vested (in units)	(651,760)
Forfeited (in units)	(50,636)
Nonvested units, ending (in units)	1,859,662	1,451,556
Outstanding, beginning (in dollars per unit)	$ 21.16
Granted (in dollars per unit)	$ 38.54	$ 25.89	$ 16.11
Vested (in dollars per unit)	$ 20.22
Forfeited (in dollars per unit)	$ 33.32
Outstanding, ending (in dollars per unit)	$ 31.54	$ 21.16

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Basis of Presentation and Significant Accounting Policies - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011 Year	Dec. 31, 2010	Dec. 31, 2009
Basis Of Presentation And Significant Accounting Policies [Line Items]
Allowance for doubtful accounts					$ 1,000,000	$ 1,000,000
Capitalized interest costs					2,000,000	1,000,000	300,000
Impairment of long-lived assets	146,499,000	0	146,499,000	0	0	38,600,000	0
Impairment of unproved oil and gas properties					2,000,000	5,000,000	7,000,000
Useful lives of other property and equipment, minimum (in years)					3
Useful lives of other property and equipment, maximum (in years)					39
Natural gas production imbalance receivables					19,000,000	18,000,000
Natural gas production imbalance payables					9,000,000	8,000,000
Restricted cash	4,000,000		4,000,000		4,000,000	3,000,000
Net deferred financing fees					94,000,000	102,000,000
Debt issuance fees amortization expense					$ 16,000,000	$ 17,000,000	$ 14,000,000

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Other Accrued Liabilities Reported on Condensed Consolidated Balance Sheets (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of Accrued Liabilities [Line Items]
Accrued compensation	$ 17,068	$ 19,581	$ 18,931
Accrued interest	91,351	55,170	62,999
Other	422	1,147	509
Other accrued liabilities	$ 108,841	$ 75,898	$ 82,439

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Earnings Per Unit (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Reconciliation of Numerators and Denominators of Basic and Diluted Per Unit Computations for Net Income Loss

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net income (loss):

	Net Income (Loss) (Numerator)			Units (Denominator)		Per Unit Amount
	(in thousands)
Three months ended June 30, 2012:
Net income:
Allocated to units	$	237,086
Allocated to unvested restricted units		(2,232	)
	$	234,854
Net income per unit:
Basic net income per unit					197,507	$	1.19
Dilutive effect of unit equivalents					653		—
Diluted net income per unit					198,160	$	1.19
Three months ended June 30, 2011:
Net income:
Allocated to units	$	237,109
Allocated to unvested restricted units		(2,475	)
	$	234,634
Net income per unit:
Basic net income per unit					175,035	$	1.34
Dilutive effect of unit equivalents					762		(0.01	)
Diluted net income per unit					175,797	$	1.33
Six months ended June 30, 2012:
Net income:
Allocated to units	$	230,884
Allocated to unvested restricted units		(2,735	)
	$	228,149
Net income per unit:
Basic net income per unit					195,382	$	1.17
Dilutive effect of unit equivalents					657		(0.01	)
Diluted net income per unit					196,039	$	1.16
Six months ended June 30, 2011:
Net loss:
Allocated to units	$	(209,573	)
Allocated to unvested restricted units		(2,439	)
	$	(212,012	)
Net loss per unit:
Basic net loss per unit					169,104	$	(1.25	)
Dilutive effect of unit equivalents					—		—
Diluted net loss per unit					169,104	$	(1.25	)

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for income (loss) from continuing operations:

	Income (Loss) (Numerator)			Units (Denominator)		Per Unit Amount
	(in thousands)
Year ended December 31, 2011:
Income from continuing operations:
Allocated to units	$	438,439
Allocated to unvested restricted units		(4,739	)
	$	433,700
Income per unit:
Basic income per unit					172,004	$	2.52
Dilutive effect of unit equivalents					725		(0.01	)
Diluted income per unit					172,729	$	2.51
Year ended December 31, 2010:
Loss from continuing operations:
Allocated to units	$	(114,288	)
Allocated to unvested restricted units		—
	$	(114,288	)
Loss per unit:
Basic loss per unit					142,535	$	(0.80	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					142,535	$	(0.80	)
Year ended December 31, 2009:
Loss from continuing operations:
Allocated to units	$	(295,841	)
Allocated to unvested restricted units		—
	$	(295,841	)
Loss per unit:
Basic loss per unit					119,307	$	(2.48	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					119,307	$	(2.48	)

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Fair Values Assumption of Unit Option Grants (Detail)	12 Months Ended
	Dec. 31, 2009 Year
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)	5
Unit Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility (in hundredths)	30.59%
Expected distributions, minimum (in hundredths)	15.80%
Expected distributions, maximum (in hundredths)	16.79%
Risk free interest rate, minimum (in hundredths)	1.24%
Risk free interest rate, maximum (in hundredths)	1.91%

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Earnings Per Unit - Additional Information (Detail) (Unit options and warrants) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Dec. 31, 2009
Unit options and warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average anti-dilutive unit equivalents excluded from computation of earnings per unit (in units)	2	2	2

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Commodity Contracts (Detail) (Commodity Contracts, USD $) In Thousands, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value assets measured on recurring basis, derivative financial instruments, assets	$ 1,413,847		$ 576,903
Fair value assets measured on recurring basis, derivative financial instruments, liabilities	3,711		17,563
Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value assets measured on recurring basis, derivative financial instruments, assets	1,730,071		880,175
Fair value assets measured on recurring basis, derivative financial instruments, liabilities	319,935		320,835
Counterparty netting under agreements governing derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value assets measured on recurring basis, derivative financial instruments, assets	(316,224)	[1]	(303,272)	[1]
Fair value assets measured on recurring basis, derivative financial instruments, liabilities	$ (316,224)	[1]	$ (303,272)	[1]

[1] Represents counterparty netting under agreements governing such derivatives.

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Business and Credit Concentrations - Additional Information (Detail)	Dec. 31, 2011 Customer	Dec. 31, 2010 Customer	Dec. 31, 2009 Customer
Sales
Concentration Risk [Line Items]
Total number of largest customers represented in sales	3	3	3
Sales | Customer 1
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	13.00%	17.00%	22.00%
Sales | Customer 2
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	10.00%	14.00%	18.00%
Sales | Customer 3
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	10.00%	13.00%	15.00%
Accounts Receivable
Concentration Risk [Line Items]
Total number of largest customers represented in sales	3	3
Accounts Receivable | Customer 1
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	12.00%	16.00%
Accounts Receivable | Customer 2
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	10.00%	12.00%
Accounts Receivable | Customer 3
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	10.00%	11.00%

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Acquisitions, Divestitures and Discontinued Operations

12 Months Ended

Dec. 31, 2011

Acquisitions, Divestitures and Discontinued Operations

Note 2—Acquisitions, Divestitures and Discontinued Operations

Acquisitions—2011

On December 15, 2011, the Company completed the acquisition of certain oil and natural gas properties located primarily in the Granite Wash of Texas and Oklahoma from Plains Exploration & Production Company (“Plains”). The results of operations of these properties have been included in the consolidated financial statements since the acquisition date. The Company paid approximately $544 million in total consideration for these properties. The transaction was financed initially with borrowings under the Company’s Credit Facility, as defined in Note 6.

On November 1, 2011, and November 18, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin. The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company paid approximately $108 million in cash and recorded a payable of approximately $2 million, resulting in total consideration for the acquisitions of approximately $110 million. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On June 1, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Cleveland play, located in the Texas Panhandle, from Panther Energy Company, LLC and Red Willow Mid-Continent, LLC (collectively referred to as “Panther”). The results of operations of these properties have been included in the consolidated financial statements since the acquisition date. The Company paid approximately $223 million in total consideration for these properties. The transaction was financed primarily with proceeds from the Company’s May 2011 debt offering, as described below.

On May 2, 2011, and May 11, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Williston Basin. The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company paid approximately $154 million in cash and recorded a receivable of approximately $1 million, resulting in total consideration for the acquisitions of approximately $153 million. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On April 1, 2011, and April 5, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin, including properties from SandRidge Exploration and Production, LLC (“SandRidge”). The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company paid approximately $239 million in total consideration for the acquisitions. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties located in the Williston Basin from an affiliate of Concho Resources Inc. (“Concho”). The results of operations of these properties have been included in the consolidated financial statements since the acquisition date. The Company paid $196 million in cash and recorded a receivable from Concho of approximately $2 million, resulting in total consideration for the acquisition of approximately $194 million. The transaction was financed primarily with proceeds from the Company’s March 2011 public offering of units, as described below.

During 2011, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The results of operations of these properties have been included in the consolidated financial statements since the acquisition dates. The Company, in the aggregate, paid approximately $38 million in total consideration for these properties.

These acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):

Assets:
Current	$	5,981
Noncurrent		748
Oil and natural gas properties		1,516,737
Total assets acquired	$	1,523,466
Liabilities:
Current	$	2,130
Asset retirement obligations		19,853
Total liabilities assumed	$	21,983
Net assets acquired	$	1,501,483

Current assets include receivables, prepaids and inventory and noncurrent assets include other property and equipment. Current liabilities include payables, ad valorem taxes payable and other liabilities.

The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate.

The revenues and expenses related to the properties acquired from Plains, Panther, SandRidge and Concho are included in the condensed consolidated results of operations of the Company as of December 15, 2011, June 1, 2011, April 1, 2011, and March 31, 2011, respectively. The following unaudited pro forma financial information presents a summary of the Company’s condensed consolidated results of operations for the years ended December 31, 2011, and December 31, 2010, assuming the acquisitions of Plains, Panther, SandRidge and Concho had been completed as of January 1, 2010, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of this date.

	Year Ended December 31,
	2011		2010
	(in thousands, except per unit amounts)
Total revenues and other	$	1,819,878	$	939,572
Total operating expenses	$	901,967	$	720,360
Net income (loss)	$	528,046	$	(86,952	)
Net income (loss) per unit:
Basic	$	3.01	$	(0.57	)
Diluted	$	3.00	$	(0.57	)

Other

In July 2010, the Company entered into a definitive purchase and sale agreement (“PSA”) to acquire certain oil and natural gas properties for a contract price of $95 million. Upon the execution of the PSA, the Company paid a deposit of approximately $9 million. In September 2010, in accordance with the terms of the PSA, the Company terminated the PSA as a result of certain conditions to closing not being met. The other party to the PSA disputed the termination of the PSA and held the deposit. On March 28, 2011, an arbitration panel granted a favorable final ruling to the Company with regard to the termination of the PSA and the return of the deposit. The deposit plus interest was received by the Company in April 2011.

Acquisitions—2010 and 2009

The following is a summary of certain significant acquisitions completed by the Company during the years ended December 31, 2010, and December 31, 2009:

• On November 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin from Element Petroleum, LP for approximately $118 million.

• On October 14, 2010, the Company completed two acquisitions of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin from Crownrock, LP and Patriot Resources Partners LLC for approximately $260 million.

• On August 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin from Crownrock, LP and Element Petroleum, LP for approximately $95 million.

• On May 27, 2010, the Company completed the acquisition of interests in Henry Savings LP and Henry Savings Management LLC that primarily hold oil and natural gas properties located in the Permian Basin for approximately $323 million.

• On April 30, 2010, the Company completed the acquisition of interests in two wholly owned subsidiaries of HighMount Exploration & Production LLC that hold oil and natural gas properties in the Antrim Shale located in northern Michigan for approximately $327 million.

• On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico from certain affiliates of Merit Energy Company for approximately $151 million.

• On August 31, 2009, and September 30, 2009, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico from Forest Oil Corporation and Forest Oil Permian Corporation for approximately $114 million.

Divestitures

In 2009, certain post-closing matters related to the 2008 sale of the deep rights interests in certain central Oklahoma acreage were resolved and the Company recorded a gain of approximately $25 million, which is included in “(gains) losses on sale of assets and other, net” on the consolidated statements of operations for the year ended December 31, 2009.

Discontinued Operations

Discontinued operations of approximately $2 million in 2009 primarily represent activity related to post-closing adjustments associated with the Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations disposed of in 2008.

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Other Property and Equipment (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 427,902	$ 197,235	$ 139,903
Less accumulated depreciation	(58,696)	(48,024)	(35,151)
Other property and equipment, net	369,206	149,211	104,752
Natural Gas Compression Plant and Pipeline
Property, Plant and Equipment [Line Items]
Other property and equipment		129,863	96,624
Buildings and Leasehold Improvements
Property, Plant and Equipment [Line Items]
Other property and equipment		16,158	10,874
Vehicles
Property, Plant and Equipment [Line Items]
Other property and equipment		13,653	10,127
Drilling And Other Equipment
Property, Plant and Equipment [Line Items]
Other property and equipment		3,645	1,827
Furniture and Office Equipment
Property, Plant and Equipment [Line Items]
Other property and equipment		29,972	17,529
Land
Property, Plant and Equipment [Line Items]
Other property and equipment		$ 3,944	$ 2,922

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Acquisitions Divestitures and Discontinued Operations - Additional Information (Detail) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended					1 Months Ended	12 Months Ended		1 Months Ended	12 Months Ended	1 Months Ended	12 Months Ended			12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Business Acquisition Plains	Dec. 31, 2011 Business Acquisition Permian Property	Jun. 01, 2011 Business Acquisition Panther	Dec. 31, 2011 Business Acquisition Panther	Dec. 31, 2011 Business Acquisition Williston Property	Apr. 05, 2011 Business Acquisition SandRidge	Dec. 31, 2011 Business Acquisition SandRidge Property	Mar. 31, 2011 Business Acquisition Concho	Dec. 31, 2011 Business Acquisition Concho	Jun. 30, 2012 Business Acquisition Various	Dec. 31, 2011 Business Acquisition Various	Dec. 31, 2011 Business Acquisition Terminated	Dec. 31, 2010 Business Acquisition Element	Dec. 31, 2010 Business Acquisition CrownQuest/Patriot Property	Dec. 31, 2010 Business Acquisition CrownQuest/Element	Dec. 31, 2010 Acquisition of interests in Henry Savings LP and Henry Savings Management LLC	Dec. 31, 2010 Acquisition of interests in two wholly owned subsidiaries of HighMount Exploration and Production LLC	Dec. 31, 2010 Acquisition of cetain oil and natural gas properties from certain affiliates of Merit Energy Company	Dec. 31, 2009 Business Acquisition Forest Oil Property
Schedule Of Business Acquisitions And Divestitures [Line Items]
Acquisition closing date								December 15, 2011	November 1, 2011, and November 18, 2011	June 1, 2011	June 1, 2011	May 2, 2011, and May 11, 2011	April 1, 2011 and April 5, 2011	April 1, 2011, and April 5, 2011	March 31, 2011	March 31, 2011				November 16, 2010	October 14, 2010	August 16, 2010	May 27, 2010	April 30, 2010	January 29, 2010	August 31, 2009, and September 30, 2009
Total consideration transferred								$ 544,000,000	$ 110,000,000	$ 224,000,000	$ 223,000,000	$ 153,000,000	$ 239,000,000	$ 239,000,000	$ 192,000,000	$ 194,000,000	$ 67,000,000	$ 38,000,000		$ 118,000,000	$ 260,000,000	$ 95,000,000	$ 323,000,000	$ 327,000,000	$ 151,000,000	$ 114,000,000
Number of acquisitions									2			2		2							2					2
Amount of cash paid to acquire the entity									108,000,000			154,000,000			194,000,000	196,000,000
Amount of payable recorded									2,000,000
Amount of receivable recorded												1,000,000			2,000,000	2,000,000
Acquisition contract price																			95,000,000
Amount of deposit included in cash paid																			9,000,000
Gain or loss on sale of assets and other, net	(36,000)	(977,000)	(1,514,000)	(1,591,000)	(3,516,000)	(6,536,000)	24,598,000
Loss from discontinued operations, net of taxes, total					$ 0	$ 0	$ (2,351,000)

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Acquisitions (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Purchase Price Allocation

The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):

Assets:
Current	$	7,358
Noncurrent		208,423
Oil and natural gas properties		1,625,246
Total assets acquired	$	1,841,027
Liabilities:
Current	$	208,139
Asset retirement obligations		34,096
Noncurrent		196,600
Total liabilities assumed	$	438,835
Net assets acquired	$	1,402,192

The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):

Assets:
Current	$	5,981
Noncurrent		748
Oil and natural gas properties		1,516,737
Total assets acquired	$	1,523,466
Liabilities:
Current	$	2,130
Asset retirement obligations		19,853
Total liabilities assumed	$	21,983
Net assets acquired	$	1,501,483

Pro Forma Financial Information

The following unaudited pro forma financial information presents a summary of the Company’s condensed consolidated results of operations for the six months ended June 30, 2012, and three months and six months ended June 30, 2011, assuming the acquisition from BP had been completed as of January 1, 2011, and the acquisitions from Plains, Panther, SandRidge and Concho had been completed as of January 1, 2010, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of these dates.

	Three Months Ended June 30,		Six Months Ended June 30,
	2011		2012		2011
	(in thousands, except per unit amounts)
Total revenues and other	$	647,633	$	1,211,569	$	640,027
Total operating expenses	$	268,273	$	779,199	$	514,965
Net income (loss)	$	276,393	$	220,419	$	(159,406	)
Net income (loss) per unit:
Basic	$	1.56	$	1.11	$	(0.94	)
Diluted	$	1.56	$	1.11	$	(0.94	)

The following unaudited pro forma financial information presents a summary of the Company’s condensed consolidated results of operations for the years ended December 31, 2011, and December 31, 2010, assuming the acquisitions of Plains, Panther, SandRidge and Concho had been completed as of January 1, 2010, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of this date.

	Year Ended December 31,
	2011		2010
	(in thousands, except per unit amounts)
Total revenues and other	$	1,819,878	$	939,572
Total operating expenses	$	901,967	$	720,360
Net income (loss)	$	528,046	$	(86,952	)
Net income (loss) per unit:
Basic	$	3.01	$	(0.57	)
Diluted	$	3.00	$	(0.57	)

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Basis of Presentation (Policies)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Principles of Consolidation and Reporting

Principles of Consolidation and Reporting

The condensed consolidated financial statements at June 30, 2012, and for the three months and six months ended June 30, 2012, and June 30, 2011, are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.

The condensed consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss) or unitholders’ capital.

Principles of Consolidation and Reporting

The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. Subsequent events were evaluated through the issuance date of the financial statements.

The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss) or unitholders’ capital.

Discontinued Operations

Discontinued Operations

Discontinued operations in 2009 primarily represent activity related to post-closing adjustments associated with the Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations disposed of in 2008.

Use of Estimates

Use of Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Use of Estimates

The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, fair values of commodity and interest rate derivatives, if any, and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuous changes in the economic environment will be reflected in the financial statements in future periods.

Cash Equivalents

Cash Equivalents

For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.

Accounts Receivable-Trade, Net

Accounts Receivable—Trade, Net

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at December 31, 2011, and December 31, 2010.

Inventories

Inventories

Materials, supplies and commodity inventories are valued at the lower of average cost or market.

Oil and Natural Gas Properties

Oil and Natural Gas Properties

Proved Properties

The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $2 million, $1 million and $300,000 for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

Impairment of Proved Properties

Based on the analysis described above, the Company recorded no impairment charge of proved oil and natural gas properties for the years ended December 31, 2011, and December 31, 2009. For the year ended December 31, 2010, the Company recorded a noncash impairment charge, before and after tax, of approximately $39 million primarily associated with proved oil and natural gas properties related to an unfavorable marketing contract. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charges are included in “impairment of long-lived assets” on the consolidated statements of operations.

Unproved Properties

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past.

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million, $5 million and $7 million for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, which are included in “exploration costs” on the consolidated statements of operations.

Impairment of proved properties

Impairment of Proved Properties

Based on the analysis described above, the Company recorded no impairment charge of proved oil and natural gas properties for the years ended December 31, 2011, and December 31, 2009. For the year ended December 31, 2010, the Company recorded a noncash impairment charge, before and after tax, of approximately $39 million primarily associated with proved oil and natural gas properties related to an unfavorable marketing contract. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charges are included in “impairment of long-lived assets” on the consolidated statements of operations.

Other Property and Equipment

Other Property and Equipment

Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from three to 39 years for the individual asset or group of assets.

Revenue Recognition

Revenue Recognition

Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.

The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2011, and December 31, 2010, the Company had natural gas production imbalance receivables of approximately $19 million and $18 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $9 million and $8 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.

The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing sales and marketing expenses.

The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in Brea, California. Any excess electricity is sold to the California wholesale power market. This revenue is included in “other revenues” on the consolidated statements of operations.

Restricted Cash

Restricted Cash

Restricted cash of approximately $4 million and $3 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2011, and December 31, 2010, respectively, and represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

Derivative Instruments

Derivative Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. These transactions are primarily in the form of swap contracts and put options. In addition, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2011, the Company had no outstanding interest rate swap agreements.

Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.

Unit-Based Compensation

Unit-Based Compensation

The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based payments granted to employees and nonemployee directors. The fair value of unit-based payments, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company currently does not have any awards accounted for as liability awards.

The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation.

The benefit of tax deductions in excess of recognized compensation costs is required to be reported as financing cash flow rather than operating cash flow. This requirement reduces net operating cash flow and increases net financing cash flow in periods in which such tax benefit exists. The amount of the Company’s excess tax benefit is reported in “excess tax benefit from unit-based compensation” on the consolidated statements of unitholders’ capital.

Deferred Financing Fees

Deferred Financing Fees

The Company incurred legal and bank fees related to the issuance of debt (see Note 6). At December 31, 2011, and December 31, 2010, net deferred financing fees of approximately $94 million and $102 million, respectively, are included in “other noncurrent assets” on the consolidated balance sheets. These debt issuance costs are amortized over the life of the debt agreement. For the years ended December 31, 2011, December 31, 2010, and December 31, 2009, amortization expense of approximately $16 million, $17 million and $14 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations.

Fair Value of Financial Instruments

Fair Value of Financial Instruments

The carrying values of the Company’s receivables, payables and Credit Facility (as defined in Note 6) are estimated to be substantially the same as their fair values at December 31, 2011, and December 31, 2010. See Note 6 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments.

Income Taxes

Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the states of Texas and Michigan, with income tax liabilities and/or benefits of the Company passed through to unitholders. As such, with the exception of the states of Texas and Michigan, the Company is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company except as described below.

Limited liability companies are subject to state income taxes in Texas and Michigan. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 14 for detail of amounts recorded in the consolidated financial statements.

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Commodity Derivatives (Detail)	Jun. 30, 2012 MmmBtu		Dec. 31, 2011 MmmBtu
2012 | Natural Gas Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	82,804		95,087
Weighted Average Fixed Price (in usd per energy unit)	5.28		5.84
2012 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	43,910		56,730
Weighted Average Fixed Price (in usd per energy unit)	5.16		5.85
2012 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	38,894	[1]	38,357
Weighted Average Short Put Price (in usd per energy unit)	5.41	[1]	5.83
2012 | Oil Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	5,981		10,367
Weighted Average Fixed Price (in usd per energy unit)	97.26		97.93
2012 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	4,730	[2]	8,171	[3]
Weighted Average Fixed Price (in usd per energy unit)	96.72	[2]	97.37	[3]
2012 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	1,251		2,196
Weighted Average Short Put Price (in usd per energy unit)	99.32		100.00
2012 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	37,535	[4]
Hedged Differential (in usd per energy unit)	(0.55)	[4]
2012 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	14,122	[4]
Hedged Differential (in usd per energy unit)	(0.20)	[4]
2012 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	4,894	[4]
Hedged Differential (in usd per energy unit)	0.12	[4]
2012 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,146	[4]
Hedged Differential (in usd per energy unit)	(0.10)	[4]
2012 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	2,282	[4]
Hedged Differential (in usd per energy unit)	(0.19)	[4]
2012 | Natural Gas Basis Differential Positions | PEPL Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)			37,735	[5]
Hedged Differential (in usd per energy unit)			(0.89)	[5]
2012 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,284	[6]	5,982	[7]
Hedged Differential (in usd per energy unit)	0.21	[6]	0.21	[7]
2013 | Natural Gas Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	173,488		101,707
Weighted Average Fixed Price (in usd per energy unit)	5.29		5.75
2013 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	87,290		64,367
Weighted Average Fixed Price (in usd per energy unit)	5.22		5.69
2013 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	86,198	[1]	37,340
Weighted Average Short Put Price (in usd per energy unit)	5.37	[1]	5.85
2013 | Oil Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	14,976		11,333
Weighted Average Fixed Price (in usd per energy unit)	95.57		98.44
2013 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	11,871	[2]	9,033	[3]
Weighted Average Fixed Price (in usd per energy unit)	94.97	[2]	98.05	[3]
2013 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,105		2,300
Weighted Average Short Put Price (in usd per energy unit)	97.86		100.00
2013 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	77,800	[4]
Hedged Differential (in usd per energy unit)	(0.56)	[4]
2013 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	34,785	[4]
Hedged Differential (in usd per energy unit)	(0.20)	[4]
2013 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	9,600	[4]
Hedged Differential (in usd per energy unit)	0.10	[4]
2013 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	5,731	[4]
Hedged Differential (in usd per energy unit)	(0.10)	[4]
2013 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	4,636	[4]
Hedged Differential (in usd per energy unit)	(0.20)	[4]
2013 | Natural Gas Basis Differential Positions | PEPL Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)			38,854	[5]
Hedged Differential (in usd per energy unit)			(0.89)	[5]
2013 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	6,944	[6]	6,315	[7]
Hedged Differential (in usd per energy unit)	0.22	[6]	0.21	[7]
2014 | Natural Gas Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	177,029		104,116
Weighted Average Fixed Price (in usd per energy unit)	5.14		5.49
2014 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	97,401		73,456
Weighted Average Fixed Price (in usd per energy unit)	5.25		5.69
2014 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	79,628	[1]	30,660
Weighted Average Short Put Price (in usd per energy unit)	5.00	[1]	5.00
2014 | Oil Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	15,863		9,034
Weighted Average Fixed Price (in usd per energy unit)	92.52		95.39
2014 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	11,903	[2]	9,034	[3]
Weighted Average Fixed Price (in usd per energy unit)	92.92	[2]	95.39	[3]
2014 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,960
Weighted Average Short Put Price (in usd per energy unit)	91.30
2014 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	79,388	[4]
Hedged Differential (in usd per energy unit)	(0.33)	[4]
2014 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	36,026	[4]
Hedged Differential (in usd per energy unit)	(0.20)	[4]
2014 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	9,490	[4]
Hedged Differential (in usd per energy unit)	0.08	[4]
2014 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	5,256	[4]
Hedged Differential (in usd per energy unit)	(0.10)	[4]
2014 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	4,891	[4]
Hedged Differential (in usd per energy unit)	(0.21)	[4]
2014 | Natural Gas Basis Differential Positions | PEPL Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)			42,194	[5]
Hedged Differential (in usd per energy unit)			(0.39)	[5]
2014 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	7,254	[6]	6,315	[7]
Hedged Differential (in usd per energy unit)	0.22	[6]	0.21	[7]
2015 | Natural Gas Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	189,895		115,340
Weighted Average Fixed Price (in usd per energy unit)	5.12		5.54
2015 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	118,041		82,490
Weighted Average Fixed Price (in usd per energy unit)	5.19		5.75
2015 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	71,854	[1]	32,850
Weighted Average Short Put Price (in usd per energy unit)	5.00	[1]	5.00
2015 | Oil Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	15,025		9,581
Weighted Average Fixed Price (in usd per energy unit)	94.81		98.25
2015 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	11,599	[2]	9,581	[3]
Weighted Average Fixed Price (in usd per energy unit)	96.23	[2]	98.25	[3]
2015 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,426
Weighted Average Short Put Price (in usd per energy unit)	90.00
2015 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	87,162	[4]
Hedged Differential (in usd per energy unit)	(0.33)	[4]
2015 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	38,362	[4]
Hedged Differential (in usd per energy unit)	(0.20)	[4]
2015 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	9,344	[4]
Hedged Differential (in usd per energy unit)	0.06	[4]
2015 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	4,891	[4]
Hedged Differential (in usd per energy unit)	(0.10)	[4]
2015 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	5,074	[4]
Hedged Differential (in usd per energy unit)	(0.21)	[4]
2015 | Natural Gas Basis Differential Positions | PEPL Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)			42,194	[5]
Hedged Differential (in usd per energy unit)			(0.39)	[5]
2015 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	7,251	[6]	840	[7]
Hedged Differential (in usd per energy unit)	0.24	[6]	0.17	[7]
2016 | Natural Gas Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	198,110		2,745
Weighted Average Fixed Price (in usd per energy unit)	4.51		5.00
2016 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	121,841		2,745
Weighted Average Fixed Price (in usd per energy unit)	4.20		5.00
2016 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	76,269	[1]
Weighted Average Short Put Price (in usd per energy unit)	5.00	[1]
2016 | Oil Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	14,735
Weighted Average Fixed Price (in usd per energy unit)	90.44
2016 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	11,464	[2]
Weighted Average Fixed Price (in usd per energy unit)	90.56	[2]
2016 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	3,271
Weighted Average Short Put Price (in usd per energy unit)	90.00
2016 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	19,764	[4]
Hedged Differential (in usd per energy unit)	(0.31)	[4]
2016 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	39,199	[4]
Hedged Differential (in usd per energy unit)	(0.20)	[4]
2016 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	4,575	[4]
Hedged Differential (in usd per energy unit)	(0.10)	[4]
2016 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	7,446	[6]
Hedged Differential (in usd per energy unit)	0.25	[6]
2017 | Natural Gas Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	187,008
Weighted Average Fixed Price (in usd per energy unit)	4.48
2017 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	120,122
Weighted Average Fixed Price (in usd per energy unit)	4.26
2017 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	66,886	[1]
Weighted Average Short Put Price (in usd per energy unit)	4.88	[1]
2017 | Oil Derivative Instruments
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	5,139
Weighted Average Fixed Price (in usd per energy unit)	89.10
2017 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	4,755	[2]
Weighted Average Fixed Price (in usd per energy unit)	89.02	[2]
2017 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	384
Weighted Average Short Put Price (in usd per energy unit)	90.00
2017 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit)	6,486	[6]
Hedged Differential (in usd per energy unit)	0.25	[6]

[1] Includes certain outstanding natural gas puts of approximately 5,329 MMMBtu for the period July 1, 2012, through December 31, 2012, 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.

[2] Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

[3] As presented in the table above, the Company has certain outstanding fixed price oil swaps on 14,750 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2016, December 31, 2017, and December 31, 2018, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

[4] Settle on the respective pricing index to hedge basis differential associated with natural gas production.

[5] Settle on the Panhandle Eastern Pipeline ("PEPL") spot price of natural gas to hedge basis differential associated with natural gas production in the Mid-Continent Deep and Mid-Continent Shallow regions.

[6] The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the "trade month roll").

[7] The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent Deep, Mid-Continent Shallow and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the "trade month roll").

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Purchase Price Allocation (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Assets:
Current	$ 7,358	$ 5,981
Noncurrent	208,423	748
Oil and natural gas properties	1,625,246	1,516,737
Total assets acquired	1,841,027	1,523,466
Liabilities:
Current	208,139	2,130
Asset retirement obligations	34,096	19,853
Noncurrent	196,600
Total liabilities assumed	438,835	21,983
Net assets acquired	$ 1,402,192	$ 1,501,483

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Unit-Based Compensation (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Unit-Based Compensation Expenses

A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
General and administrative expenses	$	6,289	$	5,290	$	13,911	$	10,694
Lease operating expenses		374		253		923		487
Total unit-based compensation expenses	$	6,663	$	5,543	$	14,834	$	11,181
Income tax benefit	$	2,462	$	2,408	$	5,481	$	4,132

A summary of unit-based compensation expenses included on the consolidated statements of operations is presented below:

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
General and administrative expenses	$	21,131	$	13,450	$	14,743
Lease operating expenses		1,112		342		346
Total unit-based compensation expenses	$	22,243	$	13,792	$	15,089
Income tax benefit	$	8,219	$	5,096	$	5,968

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Unit-Based Compensation and Other Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2011

Restricted/Unrestricted Nonvested Units

A summary of the status of the nonvested units as of December 31, 2011, is presented below:

	Number of Nonvested Units			Weighted Average Grant-Date Fair Value
Nonvested units at December 31, 2010		1,451,556		$	21.16
Granted		1,110,502		$	38.54
Vested		(651,760	)	$	20.22
Forfeited		(50,636	)	$	33.32
Nonvested units at December 31, 2011		1,859,662		$	31.54

Unit Options Activity

The following provides information related to unit option activity for the year ended December 31, 2011:

	Number of Units Underlying Options			Weighted Average Exercise Price Per Unit		Weighted Average Grant-Date Fair Value		Weighted Average Remaining Contractual Life in Years
Outstanding at December 31, 2010		1,720,393		$	22.48	$	3.05		6.71
Exercised		(310,400	)	$	23.99	$	3.83
Outstanding at December 31, 2011		1,409,993		$	22.14	$	2.87		5.83
Exercisable at December 31, 2011		1,282,526		$	22.76	$	3.11		5.70

Fair Values Assumption of Unit Option Grants

The fair values of the 2009 unit option grants were based upon the following assumptions:

	2009
Expected volatility		30.59%
Expected distributions		15.80% – 16.79%
Risk-free rate		1.24% – 1.91%
Expected term		5 years

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Basis of Presentation and Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Basis of Presentation and Significant Accounting Policies

Note 1—Basis of Presentation and Significant Accounting Policies

Nature of Business

Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company that began operations in March 2003 and was formed as a Delaware limited liability company in April 2005. The Company completed its initial public offering (“IPO”) in January 2006 and its units representing limited liability company interests (“units”) are listed on The NASDAQ Global Select Market under the symbol “LINE.” LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are located in the United States (“U.S.”), primarily in the Mid-Continent, the Permian Basin, Michigan, California and the Williston Basin.

The operations of the Company are governed by the provisions of a limited liability company agreement executed by and among its members. The agreement includes specific provisions with respect to the maintenance of the capital accounts of each of the Company’s unitholders. Pursuant to applicable provisions of the Delaware Limited Liability Company Act (the “Delaware Act”) and the Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (the “Agreement”), unitholders have no liability for the debts, obligations and liabilities of the Company, except as expressly required in the Agreement or the Delaware Act. The Company will remain in existence unless and until dissolved in accordance with the terms of the Agreement.

Principles of Consolidation and Reporting

The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. Subsequent events were evaluated through the issuance date of the financial statements.

The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss) or unitholders’ capital.

Discontinued Operations

Discontinued operations in 2009 primarily represent activity related to post-closing adjustments associated with the Company’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations disposed of in 2008.

Use of Estimates

The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, fair values of commodity and interest rate derivatives, if any, and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuous changes in the economic environment will be reflected in the financial statements in future periods.

Recently Issued Accounting Standards Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The ASU will be applied retrospectively and is effective for periods beginning on or after January 1, 2013. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

In May 2011, the FASB issued an ASU that further addresses fair value measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements. The ASU will be applied prospectively and is effective for periods beginning after December 15, 2011. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

Cash Equivalents

For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.

Accounts Receivable—Trade, Net

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at December 31, 2011, and December 31, 2010.

Inventories

Materials, supplies and commodity inventories are valued at the lower of average cost or market.

Oil and Natural Gas Properties

Proved Properties

The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $2 million, $1 million and $300,000 for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

Impairment of Proved Properties

Based on the analysis described above, the Company recorded no impairment charge of proved oil and natural gas properties for the years ended December 31, 2011, and December 31, 2009. For the year ended December 31, 2010, the Company recorded a noncash impairment charge, before and after tax, of approximately $39 million primarily associated with proved oil and natural gas properties related to an unfavorable marketing contract. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charges are included in “impairment of long-lived assets” on the consolidated statements of operations.

Unproved Properties

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past.

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million, $5 million and $7 million for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, which are included in “exploration costs” on the consolidated statements of operations.

Other Property and Equipment

Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from three to 39 years for the individual asset or group of assets.

Revenue Recognition

Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.

The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2011, and December 31, 2010, the Company had natural gas production imbalance receivables of approximately $19 million and $18 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $9 million and $8 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.

The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing sales and marketing expenses.

The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in Brea, California. Any excess electricity is sold to the California wholesale power market. This revenue is included in “other revenues” on the consolidated statements of operations.

Restricted Cash

Restricted cash of approximately $4 million and $3 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2011, and December 31, 2010, respectively, and represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

Derivative Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. These transactions are primarily in the form of swap contracts and put options. In addition, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2011, the Company had no outstanding interest rate swap agreements.

Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.

Unit-Based Compensation

The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based payments granted to employees and nonemployee directors. The fair value of unit-based payments, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company currently does not have any awards accounted for as liability awards.

The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation.

The benefit of tax deductions in excess of recognized compensation costs is required to be reported as financing cash flow rather than operating cash flow. This requirement reduces net operating cash flow and increases net financing cash flow in periods in which such tax benefit exists. The amount of the Company’s excess tax benefit is reported in “excess tax benefit from unit-based compensation” on the consolidated statements of unitholders’ capital.

Deferred Financing Fees

The Company incurred legal and bank fees related to the issuance of debt (see Note 6). At December 31, 2011, and December 31, 2010, net deferred financing fees of approximately $94 million and $102 million, respectively, are included in “other noncurrent assets” on the consolidated balance sheets. These debt issuance costs are amortized over the life of the debt agreement. For the years ended December 31, 2011, December 31, 2010, and December 31, 2009, amortization expense of approximately $16 million, $17 million and $14 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations.

Fair Value of Financial Instruments

The carrying values of the Company’s receivables, payables and Credit Facility (as defined in Note 6) are estimated to be substantially the same as their fair values at December 31, 2011, and December 31, 2010. See Note 6 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments.

Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the states of Texas and Michigan, with income tax liabilities and/or benefits of the Company passed through to unitholders. As such, with the exception of the states of Texas and Michigan, the Company is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company except as described below.

Limited liability companies are subject to state income taxes in Texas and Michigan. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 14 for detail of amounts recorded in the consolidated financial statements.

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Debt (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Debt Outstanding

The following summarizes debt outstanding:

	June 30, 2012					December 31, 2011
	Carrying Value			Fair Value(1)		Carrying Value			Fair Value(1)
	(in millions, except percentages)
Credit facility(2)	$	1,150		$	1,150	$	940		$	940
11.75% senior notes due 2017		41			45		41			46
9.875% senior notes due 2018		14			15		14			16
6.50% senior notes due May 2019		750			738		750			742
6.25% senior notes due November 2019		1,800			1,753		—			—
8.625% senior notes due 2020		1,300			1,401		1,300			1,406
7.75% senior notes due 2021		1,000			1,043		1,000			1,036
Less current maturities		—			—		—			—
		6,055		$	6,145		4,045		$	4,186
Unamortized discount		(49	)				(51	)
Total debt, net of discount	$	6,006				$	3,994

(1) The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.

(2) Variable interest rates of 2.02% and 2.57% at June 30, 2012, and December 31, 2011, respectively.

The following summarizes debt outstanding:

	December 31, 2011								December 31, 2010
	Carrying Value			Fair Value(1)		Interest Rate(2)			Carrying Value			Fair Value(1)		Interest Rate(2)
	(in millions, except percentages)
Credit facility	$	940		$	940		2.57	%	$	—		$	—		—
11.75% senior notes due 2017		41			46		12.73	%		250			288		12.73	%
9.875% senior notes due 2018		14			16		10.25	%		256			279		10.25	%
6.50% senior notes, due 2019		750			742		6.62	%		—			—		—
8.625% senior notes due 2020		1,300			1,406		9.00	%		1,300			1,396		9.00	%
7.75% senior notes due 2021		1,000			1,036		8.00	%		1,000			1,021		8.00	%
Less current maturities		—			—					—			—
		4,045		$	4,186					2,806		$	2,984
Unamortized discount		(51	)							(63	)
Total debt, net of discount	$	3,994							$	2,743

(1) The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.

(2) Represents variable interest rate for the Credit Facility and effective interest rates for the senior notes.

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Other Accrued Liabilities Reported on Condensed Consolidated Balance Sheets

“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:

	June 30, 2012		December 31, 2011
	(in thousands)
Accrued compensation	$	17,068	$	19,581
Accrued interest		91,351		55,170
Other		422		1,147
	$	108,841	$	75,898

“Other accrued liabilities” reported on the consolidated balance sheets include the following:

	December 31,
	2011		2010
	(in thousands)
Accrued compensation	$	19,581	$	18,931
Accrued interest		55,170		62,999
Other		1,147		509
	$	75,898	$	82,439

Supplemental Disclosures to Condensed Consolidated Statements of Cash Flows

Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:

	Six Months Ended June 30,
	2012			2011
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	128,617		$	124,173
Cash payments for income taxes	$	306		$	476
Noncash investing activities:
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
Fair value of assets acquired	$	1,841,027		$	850,313
Cash paid, net of cash acquired		(1,455,433	)		(847,780	)
Receivables from sellers		772			5,855
Payables to sellers		(422	)		(5,241	)
Liabilities assumed	$	385,944		$	3,147

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	247,217		$	128,807		$	73,861
Cash payments for income taxes	$	487		$	1,797		$	1,282
Noncash investing activities:
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follow:
Fair value of assets acquired	$	1,523,466		$	1,375,010		$	117,717
Cash paid		(1,500,193	)		(1,351,033	)		(115,285	)
Receivable from seller		3,557			9,976			636
Payables to sellers		(4,847	)		—			—
Liabilities assumed	$	21,983		$	33,953		$	3,068

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Debt Outstanding (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011		Dec. 31, 2010
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities	$ 6,006		$ 3,994		$ 2,743
Line of Credit | Credit Facility
Debt Instrument [Line Items]
Long-term Debt, Gross	1,150	[1]	940	[1]
Long-term Debt, Fair Value	1,150	[1],[2]	940	[1],[2],[3]
Debt Instrument, Interest Rate at Period End (in hundredths)	2.02%		2.57%	[4]
Subordinated Debt
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount	(49)		(51)		(63)
Subordinated Debt | Senior Notes Due 2017
Debt Instrument [Line Items]
Long-term Debt, Gross	41		41		250
Long-term Debt, Fair Value	45	[2]	46	[2],[3]	288	[3]
Debt Instrument, Interest Rate at Period End (in hundredths)			12.73%	[4]	12.73%	[4]
Subordinated Debt | Senior Notes Due 2018
Debt Instrument [Line Items]
Long-term Debt, Gross	14		14		256
Long-term Debt, Fair Value	15	[2]	16	[2],[3]	279	[3]
Debt Instrument, Interest Rate at Period End (in hundredths)			10.25%	[4]	10.25%	[4]
Subordinated Debt | Senior Notes Due May 2019
Debt Instrument [Line Items]
Long-term Debt, Gross	750		750
Long-term Debt, Fair Value	738	[2]	742	[2],[3]
Debt Instrument, Interest Rate at Period End (in hundredths)			6.62%	[4]
Subordinated Debt | Senior Notes Due November 2019
Debt Instrument [Line Items]
Long-term Debt, Gross	1,800
Long-term Debt, Fair Value	1,753	[2]
Subordinated Debt | Senior Notes Due 2020
Debt Instrument [Line Items]
Long-term Debt, Gross	1,300		1,300		1,300
Long-term Debt, Fair Value	1,401	[2]	1,406	[2],[3]	1,396	[3]
Debt Instrument, Interest Rate at Period End (in hundredths)			9.00%	[4]	9.00%	[4]
Subordinated Debt | Senior Notes Due 2021
Debt Instrument [Line Items]
Long-term Debt, Gross	1,000		1,000		1,000
Long-term Debt, Fair Value	1,043	[2]	1,036	[2],[3]	1,021	[3]
Debt Instrument, Interest Rate at Period End (in hundredths)			8.00%	[4]	8.00%	[4]
Less Current Maturities
Debt Instrument [Line Items]
Less current maturities
Total Debt Less Current Maturities
Debt Instrument [Line Items]
Long-term Debt	6,055		4,045		2,806
Long-term Debt, Fair Value	$ 6,145	[2]	$ 4,186	[2],[3]	$ 2,984	[3]

[1] Variable interest rates of 2.02% and 2.57% at June 30, 2012, and December 31, 2011, respectively.

[2] The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.

[3] The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.

[4] Represents variable interest rate for the Credit Facility and effective interest rates for the senior notes.

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Effective Income Tax Rate Reconciliation (Detail)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of Effective Income Tax Rate [Line Items]
Federal statutory rate	35.00%	35.00%	35.00%
State, net of federal tax benefit	0.50%	(1.20%)
Loss excluded from nontaxable entities	(34.40%)	(37.50%)	(34.30%)
Other items	0.10%	(0.10%)	0.70%
Effective rate	1.20%	(3.80%)	1.40%

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 1,883	$ 1,114	$ 236,001
Accounts receivable-trade, net	321,012	284,565	184,624
Derivative instruments	489,530	255,063	234,675
Other current assets	69,884	80,734	55,609
Total current assets	882,309	621,476	710,909
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	9,995,748	7,835,650	5,664,503
Less accumulated depletion and amortization	(1,426,132)	(1,033,617)	(719,035)
Oil and natural gas properties, successful efforts method, net	8,569,616	6,802,033	4,945,468
Other property and equipment	427,902	197,235	139,903
Less accumulated depreciation	(58,696)	(48,024)	(35,151)
Other property and equipment, net	369,206	149,211	104,752
Derivative instruments	924,317	321,840	56,895
Other noncurrent assets	434,654	105,577	115,124
Noncurrent assets, excluding property, total	1,358,971	427,417	172,019
Total noncurrent assets	10,297,793	7,378,661	5,222,239
Total assets	11,180,102	8,000,137	5,933,148
Current liabilities:
Accounts payable and accrued expenses	667,541	403,450	219,830
Derivative instruments	3,461	14,060	12,839
Other accrued liabilities	108,841	75,898	82,439
Total current liabilities	779,843	493,408	315,108
Noncurrent liabilities:
Credit facility	1,150,000	940,000	0
Senior notes, net	4,855,547	3,053,657	2,742,902
Derivative instruments	250	3,503	39,797
Other noncurrent liabilities	262,799	80,659	47,125
Total noncurrent liabilities	6,268,596	4,077,819	2,829,824
Commitments and contingencies
Unitholders' capital:
199,557,167 units, 177,364,558 units and 159,009,795 units issued and outstanding at June 30, 2012, December 31, 2011 and December 31, 2010, respectively	3,223,223	2,751,354	2,549,099
Accumulated income	908,440	677,556	239,117
Total unitholders' capital	4,131,663	3,428,910	2,788,216
Total liabilities and unitholders' capital	$ 11,180,102	$ 8,000,137	$ 5,933,148

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Pro Forma Financial Information (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended	6 Months Ended		12 Months Ended
	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010
Business Acquisition [Line Items]
Total revenues and other	$ 647,633	$ 1,211,569	$ 640,027	$ 1,819,878	$ 939,572
Total operating expenses	268,273	779,199	514,965	901,967	720,360
Net income (loss)	$ 276,393	$ 220,419	$ (159,406)	$ 528,046	$ (86,952)
Basic	$ 1.56	$ 1.11	$ (0.94)	$ 3.01	$ (0.57)
Diluted	$ 1.56	$ 1.11	$ (0.94)	$ 3.00	$ (0.57)

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CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (Parenthetical) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Underwriting discounts and expenses	$ 30,007	$ 27,427	$ 34,556	$ 12,369

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Balance Sheet Presentation (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	$ 1,730,071	$ 880,175	$ 637,836
Derivative Liability, Fair Value	$ 319,935	$ 320,835	$ 398,902

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Other Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Other Property and Equipment

Other property and equipment consists of the following:

	December 31,
	2011			2010
	(in thousands)
Natural gas compression plant and pipeline	$	129,863		$	96,624
Buildings and leasehold improvements		16,158			10,874
Vehicles		13,653			10,127
Drilling and other equipment		3,645			1,827
Furniture and office equipment		29,972			17,529
Land		3,944			2,922
		197,235			139,903
Less accumulated depreciation		(48,024	)		(35,151	)
	$	149,211		$	104,752

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Commitments and Contingencies - Additional Information (Detail) (USD $)	1 Months Ended		3 Months Ended	6 Months Ended	12 Months Ended
	Apr. 30, 2012	Mar. 31, 2011	Jun. 30, 2012	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Commitments and Contingencies Disclosure [Line Items]
Net receivable from canceled derivative contracts					$ 7,000,000	$ 7,000,000
Amount of general unsecured claims from termination agreements		51,000,000			51,000,000
Maximum value of distributions from contingency claim					51,000,000
Distribution received under termination agreement	25,000,000
Recovery of bankruptcy claim included in gains (losses) on oil and natural gas derivatives			$ 18,277,000	$ 18,277,000

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

Note 13—Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:

	June 30, 2012		December 31, 2011
	(in thousands)
Accrued compensation	$	17,068	$	19,581
Accrued interest		91,351		55,170
Other		422		1,147
	$	108,841	$	75,898

Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:

	Six Months Ended June 30,
	2012			2011
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	128,617		$	124,173
Cash payments for income taxes	$	306		$	476
Noncash investing activities:
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
Fair value of assets acquired	$	1,841,027		$	850,313
Cash paid, net of cash acquired		(1,455,433	)		(847,780	)
Receivables from sellers		772			5,855
Payables to sellers		(422	)		(5,241	)
Liabilities assumed	$	385,944		$	3,147

Included in “acquisition of oil and natural gas properties” on the condensed consolidated statement of cash flows for the six months ended June 30, 2012, is a deposit paid by the Company of approximately $308 million for the pending acquisition (see Note 2).

For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $4 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at June 30, 2012, and December 31, 2011, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facility. At June 30, 2012, and December 31, 2011, approximately $13 million and $54 million, respectively, were included in “accounts payable and accrued expenses” on the condensed consolidated balance sheets which represents reclassified net outstanding checks. The Company presents these net outstanding checks as cash flows from financing activities on the condensed consolidated statements of cash flows.

Note 15—Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows

“Other accrued liabilities” reported on the consolidated balance sheets include the following:

	December 31,
	2011		2010
	(in thousands)
Accrued compensation	$	19,581	$	18,931
Accrued interest		55,170		62,999
Other		1,147		509
	$	75,898	$	82,439

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	247,217		$	128,807		$	73,861
Cash payments for income taxes	$	487		$	1,797		$	1,282
Noncash investing activities:
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follow:
Fair value of assets acquired	$	1,523,466		$	1,375,010		$	117,717
Cash paid		(1,500,193	)		(1,351,033	)		(115,285	)
Receivable from seller		3,557			9,976			636
Payables to sellers		(4,847	)		—			—
Liabilities assumed	$	21,983		$	33,953		$	3,068

For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $4 million and $3 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2011, and December 31, 2010, respectively, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facility. At December 31, 2011, approximately $54 million was included in “accounts payable and accrued expenses” on the consolidated balance sheet which represents reclassified net outstanding checks. There was no such balance at December 31, 2010. The Company presents these net outstanding checks as cash flows from financing activities on the consolidated statements of cash flows.

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Asset Retirement Obligations (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Asset Retirement Obligations Reconciliation

The following presents a reconciliation of the asset retirement obligations (in thousands):

Asset retirement obligations at December 31, 2011	$	71,142
Liabilities added from acquisitions		34,096
Liabilities added from drilling		574
Current year accretion expense		3,373
Settlements		(1,506	)
Revision of estimates		942
Asset retirement obligations at June 30, 2012	$	108,621

The following presents a reconciliation of the Company’s asset retirement obligations:

	December 31,
	2011			2010
	(in thousands)
Asset retirement obligations at beginning of year	$	42,945		$	33,135
Liabilities added from acquisitions		19,853			6,976
Liabilities added from drilling		1,277			309
Current year accretion expense		4,140			2,694
Settlements		(2,218	)		(169	)
Revision of estimates		5,145			—
Asset retirement obligations at end of year	$	71,142		$	42,945

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Basis of Presentation

6 Months Ended

Jun. 30, 2012

Basis of Presentation

Note 1—Basis of Presentation

Nature of Business

Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company. LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are located in the United States (“U.S.”), in the Mid-Continent, the Hugoton Basin, the Permian Basin, Michigan, Illinois, the Williston/Powder River Basin, California and east Texas. Effective January 1, 2012, the Company realigned its existing regions and in May 2012 added the East Texas region and now has seven operating regions in the U.S.: Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays); Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle; Permian Basin, which includes areas in west Texas and southeast New Mexico; Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois; Williston/Powder River Basin, which includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming; California, which includes the Brea Olinda Field of the Los Angeles Basin; and East Texas, which includes properties located in east Texas. The realignment had no effect on the Company’s operations.

Principles of Consolidation and Reporting

The condensed consolidated financial statements at June 30, 2012, and for the three months and six months ended June 30, 2012, and June 30, 2011, are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.

The condensed consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss) or unitholders’ capital.

Use of Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Recently Issued Accounting Standards

In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The ASU will be applied retrospectively and is effective for periods beginning on or after January 1, 2013. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

In May 2011, the FASB issued an ASU that further addresses fair value measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements. The ASU is to be applied prospectively and is effective for periods beginning after December 15, 2011. The Company adopted the ASU effective January 1, 2012. The adoption of the requirements of the ASU, which expanded disclosures, had no effect on the Company’s results of operations or financial position.

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Operating Leases - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Operating Leases [Line Items]
Operating lease expense	$ 5	$ 5	$ 4

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flow from operating activities:
Net income (loss)	$ 230,884	$ (209,573)	$ 438,439	$ (114,288)	$ (298,192)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	260,782	145,711	334,084	238,532	201,782
Impairment of long-lived assets	146,499	0	0	38,600	0
Unit-based compensation expenses	14,834	11,181	22,243	13,792	15,089
Loss on extinguishment of debt	0	94,372	94,612	0	0
Amortization and write-off of deferred financing fees and other	15,793	12,413	23,828	27,014	21,824
(Gains) losses on sale of assets and other, net	111	(161)	(281)	1,718	(22,842)
Deferred income tax	5,991	2,790	310	3,088	(6,436)
Mark-to-market on derivatives:
Total (gains) losses	(441,678)	163,961	(449,940)	(7,303)	167,727
Cash settlements	174,316	104,512	237,134	302,875	362,936
Cash settlements on canceled derivatives			26,752	(123,865)	48,977
Premiums paid for derivatives	(583,434)	0	(134,352)	(120,376)	(93,606)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable-trade, net	(14,372)	(82,202)	(120,055)	(66,283)	29,117
(Increase) decrease in other assets	(1,840)	2,333	(2,951)	2,926	(3,051)
Increase (decrease) in accounts payable and accrued expenses	39,346	74,348	58,216	25,457	(4,675)
Increase (decrease) in other liabilities	30,339	(15,923)	(9,333)	49,031	8,154
Net cash provided by (used in) operating activities	(122,429)	303,762	518,706	270,918	426,804
Cash flow from investing activities:
Acquisition of oil and natural gas properties	(1,762,933)	(847,780)	(1,500,193)	(1,351,033)	(130,735)
Development of oil and natural gas properties	(481,140)	(225,889)	(574,635)	(204,832)	(170,458)
Purchases of other property and equipment	(22,433)	(18,657)	(55,229)	(18,181)	(7,784)
Proceeds from sale of properties and equipment and other	575	10,590	(303)	(7,362)	26,704
Net cash used in investing activities	(2,265,931)	(1,081,736)	(2,130,360)	(1,581,408)	(282,273)
Cash flow from financing activities:
Proceeds from sale of units	761,362	648,971	678,949	844,330	291,668
Proceeds from borrowings	3,954,802	1,359,240	2,534,240	3,300,816	639,203
Repayments of debt	(1,945,000)	(1,064,679)	(1,301,029)	(2,150,000)	(704,893)
Distributions to unitholders	(282,166)	(222,391)	(466,488)	(365,711)	(303,316)
Financing fees, offering expenses and other, net	(103,121)	(111,987)	(56,358)	(93,343)	(71,511)
Excess tax benefit from unit-based compensation	3,252	2,587	4,805	0	577
Purchase of units			(17,352)	(11,832)	(2,696)
Net cash provided by (used in) financing activities	2,389,129	611,741	1,376,767	1,524,260	(150,968)
Net increase (decrease) in cash and cash equivalents	769	(166,233)	(234,887)	213,770	(6,437)
Cash and cash equivalents:
Beginning	1,114	236,001	236,001	22,231	28,668
Ending	$ 1,883	$ 69,768	$ 1,114	$ 236,001	$ 22,231

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical)	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Unitholder's capital: Units issued	199,557,167	177,364,558	159,009,795
Unitholders' capital: Units outstanding	199,557,167	177,364,558	159,009,795

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Asset Retirement Obligations

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Asset Retirement Obligations

Note 9—Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2% for the six months ended June 30, 2012); and (iv) a credit-adjusted risk-free interest rate (average of 7.36% for the six months ended June 30, 2012). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

The following presents a reconciliation of the asset retirement obligations (in thousands):

Asset retirement obligations at December 31, 2011	$	71,142
Liabilities added from acquisitions		34,096
Liabilities added from drilling		574
Current year accretion expense		3,373
Settlements		(1,506	)
Revision of estimates		942
Asset retirement obligations at June 30, 2012	$	108,621

Note 10—Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for each of the years in the three-year period ended December 31, 2011); and (iv) a credit-adjusted risk-free interest rate (average of 7.5%, 8.6% and 9.6% for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively).

The following presents a reconciliation of the Company’s asset retirement obligations:

	December 31,
	2011			2010
	(in thousands)
Asset retirement obligations at beginning of year	$	42,945		$	33,135
Liabilities added from acquisitions		19,853			6,976
Liabilities added from drilling		1,277			309
Current year accretion expense		4,140			2,694
Settlements		(2,218	)		(169	)
Revision of estimates		5,145			—
Asset retirement obligations at end of year	$	71,142		$	42,945

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012
Document Information [Line Items]
Document Type	S-1
Amendment Flag	false
Document Period End Date	Jun. 30, 2012
Trading Symbol	LINE
Entity Registrant Name	LINN ENERGY, LLC
Entity Central Index Key	0001326428
Entity Filer Category	Large Accelerated Filer

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Commitments and Contingencies

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Commitments and Contingencies

Note 10—Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters. For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company. Discovery related to class certification has concluded. Briefing and the hearing on class certification have been deferred by court order pending the Tenth Circuit Court of Appeals’ resolution of interlocutory appeals of two unrelated class certification orders. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

In 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”) (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. In March 2011, the Company and Lehman entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”). In December 2011, a Chapter 11 Plan (“Plan”) was approved by the Bankruptcy Court. Based on the recovery estimates described in the approved disclosure statement relating to the Plan, the Company expects to ultimately receive a substantial portion of the Company Claim. On April 19, 2012, an initial distribution under the Plan of approximately $25 million was received by the Company resulting in a gain of approximately $18 million which is included in gains (losses) on oil and natural gas derivatives on the condensed consolidated statement of operations.

Note 11—Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits and is involved in various other disputes arising in the ordinary course of business, including claims from royalty owners related to disputed royalty payments and royalty valuations. The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters. For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company. Discovery in this dispute is ongoing and is not complete. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

On September 15, 2008, and October 3, 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”), respectively, filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. At December 31, 2011, and December 31, 2010, the Company had a net receivable of approximately $7 million from Lehman Commodity Services related to canceled derivative contracts, which is included in “other current assets” on the consolidated balance sheets. The value of the receivable was estimated based on market expectations. In March 2011, the Company, Lehman Holdings and Lehman Commodity Services entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman Holdings and Lehman Commodity Services in the amount of $51 million each, provided that the aggregate value of the distributions to the Company on account of both such claims will not exceed $51 million (collectively, the “Company Claim”). On December 6, 2011, a Chapter 11 Plan (“Plan”) was approved by the Bankruptcy Court. Initial distributions under the Plan to creditors, including the Company, are expected to occur after January 31, 2012. Based on the recovery estimates described in the approved disclosure statement relating to the Plan, the Company expects to ultimately receive a substantial portion of the Company Claim.

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Oil and Natural Gas Properties - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Noncash impairment charge, before tax	$ 146,499	$ 0	$ 146,499	$ 0	$ 0	$ 38,600	$ 0
Noncash impairment charge, after tax	$ 146,499		$ 146,499

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 347,227	$ 302,390	$ 696,122	$ 543,097	$ 1,162,037	$ 690,054	$ 408,219
Gains (losses) on oil and natural gas derivatives	439,647	205,515	441,678	(163,961)	449,940	75,211	(141,374)
Marketing revenues	10,841	1,509	12,131	2,682	5,868	3,966	4,380
Other revenues	2,882	1,157	4,756	2,280	4,609	3,049	1,924
Total revenues	800,597	510,571	1,154,687	384,098	1,622,454	772,280	273,149
Expenses:
Lease operating expenses	70,129	56,363	141,765	102,264	232,619	158,382	132,647
Transportation expenses	21,815	6,476	32,377	12,331	28,358	19,594	18,202
Marketing expenses	6,458	1,044	7,150	1,853	3,681	2,716	2,154
General and administrative expenses	41,185	31,543	84,506	62,103	133,272	99,078	86,134
Exploration costs	407	550	817	995	2,390	5,168	7,169
Bad debt expenses	(38)	33	(22)	(5)	(22)	(46)	401
Depreciation, depletion and amortization	143,506	79,345	260,782	145,711	334,084	238,532	201,782
Impairment of long-lived assets	146,499	0	146,499	0	0	38,600	0
Taxes, other than income taxes	30,656	20,318	55,851	36,045	78,522	45,182	27,605
(Gains) losses on sale of assets and other, net	36	977	1,514	1,591	3,516	6,536	(24,598)
Total expenses	460,653	196,649	731,239	362,888	816,420	613,742	451,496
Other income and (expenses):
Loss on extinguishment of debt	0	(9,810)	0	(94,372)	(94,612)	0	0
Interest expense, net of amounts capitalized	(94,390)	(62,361)	(171,909)	(125,825)	(259,725)	(193,510)	(92,701)
Losses on interest rate swaps					0	(67,908)	(26,353)
Other, net	(7,956)	(2,972)	(11,225)	(4,718)	(7,792)	(7,167)	(2,661)
Total other income and (expenses)	(102,346)	(75,143)	(183,134)	(224,915)	(362,129)	(268,585)	(121,715)
Income (loss) from continuing operations before income taxes	237,598	238,779	240,314	(203,705)	443,905	(110,047)	(300,062)
Income tax benefit (expense)	(512)	(1,670)	(9,430)	(5,868)	(5,466)	(4,241)	4,221
Income (loss) from continuing operations	237,086	237,109	230,884	(209,573)	438,439	(114,288)	(295,841)
Discontinued operations:
Losses on sale of assets, net of taxes					0	0	(158)
Loss from discontinued operations, net of taxes					0	0	(2,193)
Loss from discontinued operations, net of taxes, total					0	0	(2,351)
Net income (loss)	$ 237,086	$ 237,109	$ 230,884	$ (209,573)	$ 438,439	$ (114,288)	$ (298,192)
Income (loss) per unit-continuing operations:
Basic	$ 1.19	$ 1.34	$ 1.17	$ (1.25)	$ 2.52	$ (0.80)	$ (2.48)
Diluted	$ 1.19	$ 1.33	$ 1.16	$ (1.25)	$ 2.51	$ (0.80)	$ (2.48)
Loss per unit-discontinued operations:
Basic					$ 0.00	$ 0.00	$ (0.02)
Diluted					$ 0.00	$ 0.00	$ (0.02)
Net income (loss) per unit:
Basic (in usd per unit)	$ 1.19	$ 1.34	$ 1.17	$ (1.25)	$ 2.52	$ (0.80)	$ (2.50)
Diluted (in usd per unit)	$ 1.19	$ 1.33	$ 1.16	$ (1.25)	$ 2.51	$ (0.80)	$ (2.50)
Weighted average units outstanding:
Basic (in units)	197,507	175,035	195,382	169,104	172,004	142,535	119,307
Diluted (in units)	198,160	175,797	196,039	169,104	172,729	142,535	119,307
Distributions declared per unit (in usd per unit)	$ 0.725	$ 0.660	$ 1.415	$ 1.320	$ 2.70	$ 2.55	$ 2.52

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Unit-Based Compensation and Other Benefit Plans

12 Months Ended

Dec. 31, 2011

Unit-Based Compensation and Other Benefit Plans

Note 5—Unit-Based Compensation and Other Benefit Plans

Incentive Plan Summary

The Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (the “Plan”), originally became effective in December 2005. The Plan, which is administered by the Compensation Committee of the Board of Directors (“Compensation Committee”), permits granting unit grants, unit options, restricted units, phantom units and unit appreciation rights to employees, consultants and nonemployee directors under the terms of the Plan. The unit options and restricted units vest ratably over three years. The contractual life of unit options is 10 years. Unit awards were initially issued in conjunction with the Company’s IPO in January 2006.

The Plan limits the number of units that may be delivered pursuant to awards to 12.2 million units. The Board of Directors and the Compensation Committee have the right to alter or amend the Plan or any part of the Plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits to the participant without the consent of the participant.

Upon exercise or vesting of an award of units, or an award settled in units, the Company will issue new units, acquire units on the open market or directly from any person, or use any combination of the foregoing, at the Compensation Committee’s discretion. If the Company issues new units upon exercise or vesting of an award, the total number of units outstanding will increase. To date, the Company has issued awards of unit grants, unit options, restricted units and phantom units. The Plan provides for all of the following types of awards:

Unit Grants—A unit grant is a unit that vests immediately upon issuance.

Unit Options—A unit option is a right to purchase a unit at a specified price at terms determined by the Compensation Committee. Unit options will have an exercise price that will not be less than the fair market value of the units on the date of grant, and in general, will become exercisable over a vesting period but may accelerate upon a change in control of the Company. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s unvested unit options will be automatically forfeited unless the option agreement or the Compensation Committee provides otherwise.

Restricted Units—A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture, and may contain such terms as the Compensation Committee shall determine. The Company intends the restricted units under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of its units. Therefore, Plan participants will not pay any consideration for the restricted units they receive. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s unvested restricted units will be automatically forfeited unless the Compensation Committee or the terms of the award agreement provide otherwise.

Phantom Units/Unit Appreciation Rights—These awards may be settled in units, cash or a combination thereof. Such grants contain terms as determined by the Compensation Committee, including the period or terms over which phantom units vest. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s phantom units or unit appreciation rights will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. While phantom units require no payment from the grantee, unit appreciation rights will have an exercise price that will not be less than the fair market value of the units on the date of grant. At December 31, 2011, the Company had 36,784 phantom units issued and outstanding. To date, the Company has not issued unit appreciation rights.

Securities Authorized for Issuance Under the Plan

As of December 31, 2011, approximately 1.4 million units were issuable under the Plan pursuant to outstanding award or other agreements, and 5.2 million additional units were reserved for future issuance under the Plan.

Accounting for Unit-Based Compensation

The Company recognizes as expense, beginning at the grant date, the fair value of unit options and other equity-based compensation issued to employees and nonemployee directors. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period using the straight-line method in the Company’s consolidated statements of operations. A summary of unit-based compensation expenses included on the consolidated statements of operations is presented below:

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
General and administrative expenses	$	21,131	$	13,450	$	14,743
Lease operating expenses		1,112		342		346
Total unit-based compensation expenses	$	22,243	$	13,792	$	15,089
Income tax benefit	$	8,219	$	5,096	$	5,968

Restricted/Unrestricted Units

The fair value of unrestricted unit grants and restricted units issued is determined based on the fair market value of the Company units on the date of grant. A summary of the status of the nonvested units as of December 31, 2011, is presented below:

	Number of Nonvested Units			Weighted Average Grant-Date Fair Value
Nonvested units at December 31, 2010		1,451,556		$	21.16
Granted		1,110,502		$	38.54
Vested		(651,760	)	$	20.22
Forfeited		(50,636	)	$	33.32
Nonvested units at December 31, 2011		1,859,662		$	31.54

The weighted average grant-date fair value of unrestricted unit grants and restricted units granted was $25.89 and $16.11 during the years ended December 31, 2010, and December 31, 2009, respectively.

As of December 31, 2011, there was approximately $38 million of unrecognized compensation cost related to nonvested restricted units. The cost is expected to be recognized over a weighted average period of approximately 1.5 years. The total fair value of units that vested was approximately $13 million, $14 million and $11 million for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

In January 2012, the Company granted 913,663 restricted units as part of its annual review of its employees, including executives, compensation.

Changes in Unit Options and Unit Options Outstanding

The following provides information related to unit option activity for the year ended December 31, 2011:

	Number of Units Underlying Options			Weighted Average Exercise Price Per Unit		Weighted Average Grant-Date Fair Value		Weighted Average Remaining Contractual Life in Years
Outstanding at December 31, 2010		1,720,393		$	22.48	$	3.05		6.71
Exercised		(310,400	)	$	23.99	$	3.83
Outstanding at December 31, 2011		1,409,993		$	22.14	$	2.87		5.83
Exercisable at December 31, 2011		1,282,526		$	22.76	$	3.11		5.70

No unit options were granted during the years ended December 31, 2011, or December 31, 2010. The weighted average grant-date fair value of options granted was $0.55 during the year ended December 31, 2009. The total intrinsic value of options exercised was approximately $5 million, $2 million and $124,000, during the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively. The Company received approximately $7 million from the exercise of options during the year ended December 31, 2011.

As of December 31, 2011, total unrecognized compensation cost related to nonvested unit options was approximately $4,000. The cost is expected to be recognized over a weighted average period of approximately one month. In addition, the exercisable unit options at December 31, 2011, have an aggregate intrinsic value of approximately $19 million and all outstanding unit options have an aggregate intrinsic value of approximately $22 million. The total fair value of all options that vested during the years ended December 31, 2011, December 31, 2010, and December 31, 2009, was approximately $500,000, $1 million and $2 million, respectively. No options expired during the years ended December 31, 2011, December 31, 2010, or December 31, 2009.

The fair value of unit-based compensation for unit options was estimated on the date of grant using a Black-Scholes pricing model based on certain assumptions. The Company’s determination of the fair value of unit-based payment awards is affected by the Company’s unit price as well as assumptions regarding a number of complex and subjective variables. The Company’s employee unit options have various restrictions including vesting provisions and restrictions on transfers and hedging, among others, and often are expected to be exercised prior to their contractual maturity.

Expected volatilities used in the estimation of fair value have been determined using available volatility data for the Company as well as an average of volatility computations of other identified peer companies in the oil and natural gas industry. Expected distributions are estimated based on the Company’s distribution rate at the date of grant. Historical data of the Company and other identified peer companies is used to estimate expected term because, due to the limited period of time its equity units have been publicly traded, the Company does not have sufficient historical exercise data to compute a reasonable estimate. Forfeitures are estimated using historical Company data and are revised, if necessary, in subsequent periods if actual forfeitures differ from estimates. All employees granted awards have been determined to have similar behaviors for purposes of determining the expected term used to estimate fair value. The risk-free rate for periods within the expected term of the unit option is based on the U.S. Treasury yield curve in effect at the time of grant. The fair values of the 2009 unit option grants were based upon the following assumptions:

	2009
Expected volatility		30.59%
Expected distributions		15.80% – 16.79%
Risk-free rate		1.24% – 1.91%
Expected term		5 years

Although the fair value of unit option grants is determined in accordance with applicable accounting standards, using a Black-Scholes pricing model, that value may not be indicative of the fair value observed in a willing buyer/willing seller market transaction.

Nonemployee Grants

During the year ended December 31, 2007, the Company granted an aggregate 150,000 unit warrants to certain individuals in connection with an acquisition transition services agreement. The unit warrants, all of which remain outstanding, have an exercise price of $25.50 per unit warrant, are fully exercisable at December 31, 2011, and expire 10 years from the date of issuance.

Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan for eligible employees. Company contributions to the 401(k) plan consisted of a discretionary matching contribution equal to 100% of the first 4% of eligible compensation contributed by the employee on a before-tax basis for the year ending December 31, 2009. For the years ended December 31, 2011, and December 31, 2010, the Company contribution was equal to 100% of the first 6% of eligible employee compensation. The Company contributed approximately $4 million, $3 million and $2 million during the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively, to the 401(k) plan’s trustee account. The 401(k) plan funds are held in a trustee account on behalf of the plan participants.

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Business and Credit Concentrations

12 Months Ended

Dec. 31, 2011

Business and Credit Concentrations

Note 4—Business and Credit Concentrations

Cash

The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on its cash.

Revenue and Trade Receivables

The Company has a concentration of customers who are engaged in oil and natural gas purchasing, transportation and/or refining within the U.S. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company’s customers consist primarily of major oil and natural gas purchasers and the Company generally does not require collateral since it has not experienced significant credit losses on such sales. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectibility (see Note 1).

For the year ended December 31, 2011, the Company’s three largest customers represented 13%, 10% and 10%, respectively, of the Company’s sales. For the year ended December 31, 2010, the Company’s three largest customers represented 17%, 14% and 13%, respectively, of the Company’s sales. For the year ended December 31, 2009, the Company’s three largest customers represented 22%, 18% and 15%, respectively, of the Company’s sales.

At December 31, 2011, trade accounts receivable from three customers represented approximately 12%, 10% and 10%, respectively, of the Company’s receivables. At December 31, 2010, trade accounts receivable from three customers represented approximately 16%, 12% and 11%, respectively, of the Company’s receivables.

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Subsidiary Guarantors

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Subsidiary Guarantors

Note 14—Subsidiary Guarantors

The November 2019 Senior Notes, the May 2019 Senior Notes, the 2010 Issued Notes and the Original Senior Notes are guaranteed by all of the Company’s material subsidiaries. The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

Note 16—Subsidiary Guarantors

The 2019 Senior Notes, the 2010 Issued Notes and the Original Senior Notes are guaranteed by all of the Company’s material subsidiaries. The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

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Earnings Per Unit

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Earnings Per Unit

Note 11—Earnings Per Unit

Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net income (loss):

	Net Income (Loss) (Numerator)			Units (Denominator)		Per Unit Amount
	(in thousands)
Three months ended June 30, 2012:
Net income:
Allocated to units	$	237,086
Allocated to unvested restricted units		(2,232	)
	$	234,854
Net income per unit:
Basic net income per unit					197,507	$	1.19
Dilutive effect of unit equivalents					653		—
Diluted net income per unit					198,160	$	1.19
Three months ended June 30, 2011:
Net income:
Allocated to units	$	237,109
Allocated to unvested restricted units		(2,475	)
	$	234,634
Net income per unit:
Basic net income per unit					175,035	$	1.34
Dilutive effect of unit equivalents					762		(0.01	)
Diluted net income per unit					175,797	$	1.33
Six months ended June 30, 2012:
Net income:
Allocated to units	$	230,884
Allocated to unvested restricted units		(2,735	)
	$	228,149
Net income per unit:
Basic net income per unit					195,382	$	1.17
Dilutive effect of unit equivalents					657		(0.01	)
Diluted net income per unit					196,039	$	1.16
Six months ended June 30, 2011:
Net loss:
Allocated to units	$	(209,573	)
Allocated to unvested restricted units		(2,439	)
	$	(212,012	)
Net loss per unit:
Basic net loss per unit					169,104	$	(1.25	)
Dilutive effect of unit equivalents					—		—
Diluted net loss per unit					169,104	$	(1.25	)

There were no anti-dilutive unit equivalents for the three months or six months ended June 30, 2012, or the three months ended June 30, 2011. Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 2 million unit options and warrants for the six months ended June 30, 2011. All equivalent units were anti-dilutive for the six months ended June 30, 2011.

Note 12—Earnings Per Unit

Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for income (loss) from continuing operations:

	Income (Loss) (Numerator)			Units (Denominator)		Per Unit Amount
	(in thousands)
Year ended December 31, 2011:
Income from continuing operations:
Allocated to units	$	438,439
Allocated to unvested restricted units		(4,739	)
	$	433,700
Income per unit:
Basic income per unit					172,004	$	2.52
Dilutive effect of unit equivalents					725		(0.01	)
Diluted income per unit					172,729	$	2.51
Year ended December 31, 2010:
Loss from continuing operations:
Allocated to units	$	(114,288	)
Allocated to unvested restricted units		—
	$	(114,288	)
Loss per unit:
Basic loss per unit					142,535	$	(0.80	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					142,535	$	(0.80	)
Year ended December 31, 2009:
Loss from continuing operations:
Allocated to units	$	(295,841	)
Allocated to unvested restricted units		—
	$	(295,841	)
Loss per unit:
Basic loss per unit					119,307	$	(2.48	)
Dilutive effect of unit equivalents					—		—
Diluted loss per unit					119,307	$	(2.48	)

There were no anti-dilutive unit equivalents for the year ended December 31, 2011. Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 2 million unit options and warrants for each of the years ended December 31, 2010, and December 31, 2009. All equivalent units were anti-dilutive for the years ended December 31, 2010, and December 31, 2009, respectively.

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Fair Value Measurements on a Recurring Basis

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Fair Value Measurements on a Recurring Basis

Note 8—Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives.

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:

	June 30, 2012
	Level 2		Netting(1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	1,730,071	$	(316,224	)	$	1,413,847
Liabilities:
Commodity derivatives	$	319,935	$	(316,224	)	$	3,711

(1) Represents counterparty netting under agreements governing such derivatives.

Note 8—Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives and, when applicable, its interest rate derivatives at fair value (see Note 7) on a recurring basis. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives and, when applicable, its interest rate derivatives.

Fair Value Hierarchy

In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1	Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.
Level 2	Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives and interest rate swaps).
Level 3	Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:

	Fair Value Measurements on a Recurring Basis December 31, 2011
	Level 2		Netting(1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	880,175	$	(303,272	)	$	576,903
Liabilities:
Commodity derivatives	$	320,835	$	(303,272	)	$	17,563

(1) Represents counterparty netting under agreements governing such derivatives.

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Gains and Losses on Derivatives (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended								1 Months Ended	12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Commodity Contract	Dec. 31, 2010 Commodity Contract	Dec. 31, 2009 Commodity Contract	Dec. 31, 2010 Interest Rate Swap	Dec. 31, 2009 Interest Rate Swap	Jul. 31, 2009 Cancelled Derivatives	Dec. 31, 2011 Cancelled Derivatives	Dec. 31, 2010 Cancelled Derivatives	Dec. 31, 2009 Cancelled Derivatives
Realized gains (losses):
Total realized gains (losses)					$ 256,989	$ 175,701	$ 407,064	$ 230,237	$ 307,587	$ 400,968	$ (8,021)	$ (42,881)	$ 45,000	$ 26,752	$ (123,865)	$ 48,977
Unrealized gains (losses):
Total realized gains (losses)					192,951	(168,398)	(574,791)	192,951	(232,376)	(591,379)	63,978	16,588
Total gains (losses):
Gains (losses) on oil and natural gas derivatives	439,647	205,515	441,678	(163,961)	449,940	75,211	(141,374)
Losses on interest rate swaps					0	(67,908)	(26,353)
Total gains (losses) on derivative instruments			441,678	(163,961)	449,940	7,303	(167,727)
Realized gains:
Commodity derivatives	117,740	42,081	172,995	97,890
Recovery of bankruptcy claim (see Note 10)	18,277		18,277
Total Realized Gains (Loses)	136,017	42,081	191,272	97,890
Unrealized gains (losses):
Commodity derivatives	303,630	163,434	250,406	(261,851)
Total gains (losses):
Total	$ 439,647	$ 205,515	$ 441,678	$ (163,961)

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Debt

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Debt

Note 6—Debt

The following summarizes debt outstanding:

	June 30, 2012					December 31, 2011
	Carrying Value			Fair Value(1)		Carrying Value			Fair Value(1)
	(in millions, except percentages)
Credit facility(2)	$	1,150		$	1,150	$	940		$	940
11.75% senior notes due 2017		41			45		41			46
9.875% senior notes due 2018		14			15		14			16
6.50% senior notes due May 2019		750			738		750			742
6.25% senior notes due November 2019		1,800			1,753		—			—
8.625% senior notes due 2020		1,300			1,401		1,300			1,406
7.75% senior notes due 2021		1,000			1,043		1,000			1,036
Less current maturities		—			—		—			—
		6,055		$	6,145		4,045		$	4,186
Unamortized discount		(49	)				(51	)
Total debt, net of discount	$	6,006				$	3,994

(1) The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.

(2) Variable interest rates of 2.02% and 2.57% at June 30, 2012, and December 31, 2011, respectively.

Credit Facility

The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. In October 2011, as part of the semi-annual redetermination, a borrowing base of $3.0 billion was approved by the lenders with a maximum commitment amount of $1.5 billion. In February 2012, lenders approved an increase in the maximum commitment amount to $2.0 billion. In May 2012, the Company entered into an amendment to its Credit Facility to increase the borrowing base to $3.5 billion and extend the maturity date from April 2016 to April 2017.

During the six months ended June 30, 2012, in connection with amendments to its Credit Facility, the Company incurred financing fees and expenses of approximately $5 million, which will be amortized over the life of the Credit Facility. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.

At June 30, 2012, available borrowing capacity under the Credit Facility was approximately $646 million, which includes a $4 million reduction in availability for outstanding letters of credit and a $200 million reduction in availability related to a restriction on swap agreements outstanding associated with the pending acquisition (see Note 2). The $200 million reduction in availability under the Credit Facility will no longer apply once the pending acquisition has closed.

In July 2012, the Company entered into an amendment to its Credit Facility to increase the maximum commitment amount from $2.0 billion to $3.0 billion.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October, as well as upon requested interim redeterminations, by the lenders at their sole discretion. The Company also has the right to request one additional borrowing base redetermination per year at its discretion, as well as the right to an additional redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the Credit Facility are secured by mortgages on its and certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in its direct and indirect material subsidiaries. The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on the most recent reserve report, or 2) a Collateral Coverage Ratio of at least 2.5 to 1. Collateral Coverage Ratio is defined as ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material subsidiaries and are required to be guaranteed by any future material subsidiaries.

At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR. The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base. The Company is in compliance with all financial and other covenants of the Credit Facility.

Senior Notes Due November 2019

On March 2, 2012, the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (“November 2019 Senior Notes”) at a price of 99.989%. The November 2019 Senior Notes were sold to a group of initial purchasers and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company received net proceeds of approximately $1.77 billion (after deducting the initial purchasers’ discount of $198,000 and offering expenses of approximately $29 million). The Company used the net proceeds to fund the BP acquisition (see Note 2). The remaining proceeds were used to repay indebtedness under the Company’s Credit Facility and for general corporate purposes. The financing fees and expenses of approximately $29 million incurred in connection with the November 2019 Senior Notes will be amortized over the life of the notes. Such amortized financing fees and expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.

The November 2019 Senior Notes were issued under an indenture dated March 2, 2012 (“November 2019 Indenture”), mature November 1, 2019, and bear interest at 6.25%. Interest is payable semi-annually on May 1 and November 1, beginning November 1, 2012. The November 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries has guaranteed the November 2019 Senior Notes on a senior unsecured basis. The November 2019 Indenture provides that the Company may redeem: (i) on or prior to November 1, 2015, up to 35% of the aggregate principal amount of the November 2019 Senior Notes at a redemption price of 106.25% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the November 2019 Indenture) and accrued and unpaid interest; and (iii) on or after November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to 103.125%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The November 2019 Indenture also provides that, if a change of control (as defined in the November 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the November 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The November 2019 Indenture contains covenants substantially similar to those under the Company’s May 2019 Senior Notes, 2010 Issued Senior Notes and Original Senior Notes, as defined below, that, among other things, limit the Company’s ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of the November 2019 Senior Notes.

In connection with the issuance and sale of the November 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“November 2019 Registration Rights Agreement”) with the initial purchasers. Under the November 2019 Registration Rights Agreement, the Company agreed to use its reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the November 2019 Senior Notes in exchange for outstanding November 2019 Senior Notes within 400 days after the notes were issued. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the November 2019 Senior Notes. If the Company fails to satisfy these obligations, the Company may be required to pay additional interest to holders of the November 2019 Senior Notes under certain circumstances.

Senior Notes Due May 2019

On May 13, 2011, the Company issued $750 million in aggregate principal amount of 6.50% senior notes due 2019 (the “May 2019 Senior Notes”). The indentures related to the May 2019 Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes. On May 8, 2012, the Company filed a registration statement on Form S-4 to register exchange notes that are also substantially similar to the November 2019 Senior Notes. As of July 26, 2012, the registration statement has not been declared effective. The deadline for registration has passed and the Company will be required to pay additional interest which is expected to be less than $500,000.

Senior Notes Due 2020 and Senior Notes Due 2021

The Company has $1.3 billion in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”) and $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (the “2021 Senior Notes,” and together with the 2020 Senior Notes, the “2010 Issued Senior Notes”). The indentures related to the 2010 Issued Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes. However, in 2011, the Company caused the trustee to remove the restrictive legends from each of the 2010 Issued Senior Notes making them freely tradable (other than with respect to persons that are affiliates of the Company), thereby terminating the Company’s obligations under each of the registration rights agreements entered into in connection with the issuance of the 2010 Issued Senior Notes.

Senior Notes Due 2017 and Senior Notes Due 2018

The Company also has $41 million (originally $250 million) in aggregate principal amount of 11.75% senior notes due 2017 (the “2017 Senior Notes”) and $14 million (originally $256 million) in aggregate principal amount of 9.875% senior notes due 2018 (the “2018 Senior Notes” and together with the 2017 Senior Notes, the “Original Senior Notes”). The indentures related to the Original Senior Notes initially contained redemption provisions and covenants that were substantially similar to those of the November 2019 Senior Notes; however, in conjunction with the tender offers in 2011, the indentures were amended and most of the covenants and certain default provisions were eliminated. The amendments became effective upon the execution of the supplemental indentures to the indentures governing the Original Senior Notes.

In March 2011 and June 2011, in accordance with the indentures related to the Original Senior Notes, the Company redeemed and also repurchased through cash tender offers, a portion of the Original Senior Notes. In connection with the redemptions and cash tender offers of a portion of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $10 million and $94 million for the three months and six months ended June 30, 2011, respectively.

Note 6—Debt

The following summarizes debt outstanding:

	December 31, 2011								December 31, 2010
	Carrying Value			Fair Value(1)		Interest Rate(2)			Carrying Value			Fair Value(1)		Interest Rate(2)
	(in millions, except percentages)
Credit facility	$	940		$	940		2.57	%	$	—		$	—		—
11.75% senior notes due 2017		41			46		12.73	%		250			288		12.73	%
9.875% senior notes due 2018		14			16		10.25	%		256			279		10.25	%
6.50% senior notes, due 2019		750			742		6.62	%		—			—		—
8.625% senior notes due 2020		1,300			1,406		9.00	%		1,300			1,396		9.00	%
7.75% senior notes due 2021		1,000			1,036		8.00	%		1,000			1,021		8.00	%
Less current maturities		—			—					—			—
		4,045		$	4,186					2,806		$	2,984
Unamortized discount		(51	)							(63	)
Total debt, net of discount	$	3,994							$	2,743

(1) The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.

(2) Represents variable interest rate for the Credit Facility and effective interest rates for the senior notes.

Credit Facility

On May 2, 2011, the Company entered into a Fifth Amended and Restated Credit Agreement (“Credit Facility”), which provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount of $1.5 billion. In October 2011, as part of the semi-annual redetermination, a borrowing base of $3.0 billion was approved by the lenders with the maximum commitment amount remaining unchanged at $1.5 billion. The maturity date is April 2016.

During 2011, in connection with amendments to its Credit Facility, the Company incurred financing fees and expenses of approximately $4 million, which will be amortized over the life of the Credit Facility. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations. At December 31, 2011, available borrowing capacity under the Credit Facility was $556 million, which includes a $4 million reduction in availability for outstanding letters of credit.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October, as well as upon requested interim redeterminations, by the lenders at their sole discretion. The Company also has the right to request one additional borrowing base redetermination per year at its discretion, as well as the right to an additional redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the Credit Facility are secured by mortgages on its and certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in its direct and indirect material subsidiaries. The Company and its subsidiaries are required to maintain the mortgages on properties representing at least 80% of the total value of its and its subsidiaries’ oil and natural gas properties. Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material subsidiaries and are required to be guaranteed by any future material subsidiaries.

At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR. The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum equal to 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base. The Company is in compliance with all financial and other covenants of the Credit Facility.

Senior Notes Due 2019

On May 13, 2011, the Company issued $750 million in aggregate principal amount of 6.50% senior notes due 2019 (the “2019 Senior Notes”) at a price of 99.232%. The 2019 Senior Notes were sold to a group of initial purchasers and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company received net proceeds of approximately $729 million (after deducting the initial purchasers’ discount and offering expenses). The Company used a portion of the net proceeds to repay all of the outstanding indebtedness under its Credit Facility, fund or partially fund acquisitions and for general corporate purposes. In connection with the 2019 Senior Notes, the Company incurred financing fees and expenses of approximately $15 million, which will be amortized over the life of the 2019 Senior Notes. The discount on the 2019 Senior Notes, which totaled approximately $6 million, will also be amortized over the life of the 2019 Senior Notes. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations.

The 2019 Senior Notes were issued under an indenture dated May 13, 2011 (“2019 Indenture”), mature May 15, 2019, and bear interest at 6.50%. Interest is payable semi-annually on May 15 and November 15, beginning November 15, 2011. The 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries has guaranteed the 2019 Senior Notes on a senior unsecured basis. The 2019 Indenture provides that the Company may redeem: (i) on or prior to May 15, 2014, up to 35% of the aggregate principal amount of the 2019 Senior Notes at a redemption price of 106.50% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to May 15, 2015, all or part of the 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the 2019 Indenture) and accrued and unpaid interest; and (iii) on or after May 15, 2015, all or part of the 2019 Senior Notes at a redemption price equal to 103.250%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The 2019 Indenture also provides that, if a change of control (as defined in the 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The 2019 Indenture contains covenants substantially similar to those under the Company’s 2010 Issued Senior Notes and Original Senior Notes, as defined below, that, among other things, limit the Company’s ability to: (i) pay distributions, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of the 2019 Senior Notes.

In connection with the issuance and sale of the 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“2019 Registration Rights Agreement”) with the initial purchasers. Under the 2019 Registration Rights Agreement, the Company agreed to use reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the 2019 Senior Notes in exchange for outstanding 2019 Senior Notes within 400 days after the notes were issued. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the 2019 Senior Notes. If the Company fails to satisfy these obligations, the Company may be required to pay additional interest to holders of the 2019 Senior Notes under certain circumstances.

Senior Notes Due 2020 and Senior Notes Due 2021

On April 6, 2010, the Company issued $1.30 billion in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”). On September 13, 2010, the Company issued $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (the “2021 Senior Notes,” and together with the 2020 Senior Notes, the “2010 Issued Senior Notes”). The indentures related to the 2010 Issued Senior Notes contain redemption provisions and covenants that are substantially similar to those of the 2019 Senior Notes.

Senior Notes Due 2017 and Senior Notes Due 2018

The Company also has $41 million (originally $250 million) in aggregate principal amount of 11.75% senior notes due 2017 (the “2017 Senior Notes”) and $14 million (originally $256 million) in aggregate principal amount of 9.875% senior notes due 2018 (the “2018 Senior Notes” and together with the 2017 Senior Notes, the “Original Senior Notes”). The indentures related to the Original Senior Notes originally contained redemption provisions and covenants that were substantially similar to those of the 2010 Issued Senior Notes; however, in connection with the tender offers described below, the indentures were amended and most of the covenants and certain default provisions were eliminated.

Redemptions of Original Senior Notes

In March 2011, in accordance with the provisions of the indentures related to the 2017 Senior Notes and the 2018 Senior Notes, the Company redeemed 35%, or $87 million and $90 million, respectively, of each of its original aggregate principal amount of the 2017 Senior Notes and 2018 Senior Notes. After the redemptions, $163 million and $166 million, respectively, of the 2017 Senior Notes and 2018 Senior Notes remained outstanding.

Tender Offers for and Repurchase of Original Senior Notes

On February 28, 2011, the Company commenced cash tender offers (“Offers”) and related consent solicitations to purchase any and all of its outstanding 2017 Senior Notes and 2018 Senior Notes. The Offers expired on March 25, 2011. Holders who validly tendered 2017 Senior Notes and 2018 Senior Notes on or before March 14, 2011, received total consideration of $1,212.50 and $1,172.50, respectively, for each $1,000 principal amount of such notes accepted for purchase. Total consideration included a consent payment of $30.00 per $1,000 principal amount of notes accepted for purchase. Holders who validly tendered 2017 Senior Notes and 2018 Senior Notes after March 14, 2011, but before March 25, 2011, received $1,182.50 and $1,142.50, respectively, for each $1,000 principal amount of such notes accepted for purchase.

In March 2011, in connection with its Offers and related consent solicitations, the Company accepted and purchased: 1) $105 million of the aggregate principal amount of its outstanding 2017 Senior Notes (or 65% of the remaining outstanding principal amount of its 2017 Senior Notes), and 2) $126 million of the aggregate principal amount of its outstanding 2018 Senior Notes (or 76% of the remaining outstanding principal amount of its 2018 Senior Notes).

In conjunction with each tender offer, the Company received consents to amendments to the indentures of the 2017 Senior Notes and 2018 Senior Notes, which eliminated most of the covenants and certain default provisions applicable to the series of notes issued under such indentures. The amendments became effective upon the execution of the supplemental indentures to the indentures governing each of the 2017 Senior Notes and the 2018 Senior Notes.

In June 2011, the Company repurchased an additional portion of its remaining outstanding 2017 Senior Notes and 2018 Senior Notes for approximately $17 million (or 29% of the remaining outstanding principal amount of its 2017 Senior Notes) and approximately $24 million (or 61% of the remaining outstanding principal amount of its 2018 Senior Notes), respectively. In December 2011, the Company also repurchased an additional portion of its remaining outstanding 2018 Senior Notes for approximately $2 million (or 9% of the remaining outstanding principal amount of its 2018 Senior Notes). After giving effect to the tender offers and subsequent repurchases of the 2017 Senior Notes and the 2018 Senior Notes, aggregate principal amounts of $41 million and $14 million, respectively, remain outstanding at December 31, 2011.

In connection with the redemptions, cash tender offers and additional repurchases of a portion of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $95 million for the year ended December 31, 2011.

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Derivatives

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Derivatives

Note 7—Derivatives

Commodity Derivatives

The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes derivative positions for the periods indicated as of June 30, 2012:

	July 1 – December 31, 2012			2013			2014			2015			2016			2017
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		43,910			87,290			97,401			118,041			121,841			120,122
Average price ($/MMBtu)	$	5.16		$	5.22		$	5.25		$	5.19		$	4.20		$	4.26
Puts:(1)
Hedged volume (MMMBtu)		38,894			86,198			79,628			71,854			76,269			66,886
Average price ($/MMBtu)	$	5.41		$	5.37		$	5.00		$	5.00		$	5.00		$	4.88
Total:
Hedged volume (MMMBtu)		82,804			173,488			177,029			189,895			198,110			187,008
Average price ($/MMBtu)	$	5.28		$	5.29		$	5.14		$	5.12		$	4.51		$	4.48
Oil positions:
Fixed price swaps:(2)
Hedged volume (MBbls)		4,730			11,871			11,903			11,599			11,464			4,755
Average price ($/Bbl)	$	96.72		$	94.97		$	92.92		$	96.23		$	90.56		$	89.02
Puts:
Hedged volume (MBbls)		1,251			3,105			3,960			3,426			3,271			384
Average price ($/Bbl)	$	99.32		$	97.86		$	91.30		$	90.00		$	90.00		$	90.00
Total:
Hedged volume (MBbls)		5,981			14,976			15,863			15,025			14,735			5,139
Average price ($/Bbl)	$	97.26		$	95.57		$	92.52		$	94.81		$	90.44		$	89.10
Natural gas basis differential positions:(3)
Panhandle basis swaps:
Hedged volume (MMMBtu)		37,535			77,800			79,388			87,162			19,764			—
Hedged differential ($/MMBtu)	$	(0.55	)	$	(0.56	)	$	(0.33	)	$	(0.33	)	$	(0.31	)	$	—
NWPL—Rockies basis swaps:
Hedge volume (MMMBtu)		14,122			34,785			36,026			38,362			39,199			—
Hedge differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	—
MichCon basis swaps:
Hedged volume (MMMBtu)		4,894			9,600			9,490			9,344			—			—
Hedged differential ($/MMBtu)	$	0.12		$	0.10		$	0.08		$	0.06		$	—		$	—
Houston Ship Channel basis swaps:
Hedged volume (MMMBtu)		3,146			5,731			5,256			4,891			4,575			—
Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	—
Permian basis swaps:
Hedged volume (MMMBtu)		2,282			4,636			4,891			5,074			—			—
Hedged differential ($/MMBtu)	$	(0.19	)	$	(0.20	)	$	(0.21	)	$	(0.21	)	$	—		$	—
Oil timing differential positions:
Trade month roll swaps:(4)
Hedged volume (MBbls)		3,284			6,944			7,254			7,251			7,446			6,486
Hedged differential ($/Bbl)	$	0.21		$	0.22		$	0.22		$	0.24		$	0.25		$	0.25

(1) Includes certain outstanding natural gas puts of approximately 5,329 MMMBtu for the period July 1, 2012, through December 31, 2012, 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.

(2) Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

(3) Settle on the respective pricing index to hedge basis differential associated with natural gas production.

(4) The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the six months ended June 30, 2012, the Company entered into commodity derivative contracts consisting of oil and natural gas swaps and puts for 2012 through 2017, and paid premiums for put options of approximately $583 million. Also during the six months ended June 30, 2012, the Company entered into natural gas basis swaps for 2012 through 2016 and trade month roll swaps for 2012 through 2017.

Settled derivatives on natural gas production for the three months and six months ended June 30, 2012, included volumes of 34,438 MMMBtu and 58,080 MMMBtu, respectively, at average contract prices of $5.45 per MMBtu and $5.61 per MMBtu. Settled derivatives on oil production for the three months and six months ended June 30, 2012, included volumes of 2,731 MBbls and 5,308 MBbls, respectively, at average contract prices of $98.08 and $98.01 per Bbl. Settled derivatives on natural gas production for the three months and six months ended June 30, 2011, included volumes of 16,106 MMMBtu and 32,178 MMMBtu, respectively, at average contract prices of $8.24 per MMBtu and $8.25 per MMBtu. Settled derivatives on oil production for the three months and six months ended June 30, 2011, included volumes of 1,839 MBbls and 3,671 MBbls, respectively, at an average contract price of $84.08 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.

Balance Sheet Presentation

The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:

	June 30, 2012		December 31, 2011
	(in thousands)
Assets:
Commodity derivatives	$	1,730,071	$	880,175
Liabilities:
Commodity derivatives	$	319,935	$	320,835

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1.7 billion at June 30, 2012. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on derivatives, including realized and unrealized gains and losses, are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.” Realized gains (losses), excluding canceled derivatives, represent amounts related to the settlement of derivative instruments and are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are noncash items.

The following presents the Company’s reported gains and losses on derivative instruments:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Realized gains:
Commodity derivatives	$	117,740	$	42,081	$	172,995	$	97,890
Recovery of bankruptcy claim (see Note 10)		18,277		—		18,277		—
		136,017		42,081		191,272		97,890
Unrealized gains (losses):
Commodity derivatives		303,630		163,434		250,406		(261,851	)
Total gains (losses):
Total	$	439,647	$	205,515	$	441,678	$	(163,961	)

Note 7—Derivatives

Commodity Derivatives

The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales. At December 31, 2011, the Company had no outstanding collars. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes open positions as of December 31, 2011, and represents, as of such date, derivatives in place through December 31, 2016, on annual production volumes:

	2012			2013			2014			2015			2016
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)		56,730			64,367			73,456			82,490			2,745
Average price ($/MMBtu)	$	5.85		$	5.69		$	5.69		$	5.75		$	5.00
Puts:
Hedged volume (MMMBtu)		38,357			37,340			30,660			32,850			—
Average price ($/MMBtu)	$	5.83		$	5.85		$	5.00		$	5.00		$	—
Total:
Hedged volume (MMMBtu)		95,087			101,707			104,116			115,340			2,745
Average price ($/MMBtu)	$	5.84		$	5.75		$	5.49		$	5.54		$	5.00
Oil positions:
Fixed price swaps:(1)
Hedged volume (MBbls)		8,171			9,033			9,034			9,581			—
Average price ($/Bbl)	$	97.37		$	98.05		$	95.39		$	98.25		$	—
Puts:
Hedged volume (MBbls)		2,196			2,300			—			—			—
Average price ($/Bbl)	$	100.00		$	100.00		$	—		$	—		$	—
Total:
Hedged volume (MBbls)		10,367			11,333			9,034			9,581			—
Average price ($/Bbl)	$	97.93		$	98.44		$	95.39		$	98.25		$	—
Natural gas basis differential positions:
PEPL basis swaps:(2)
Hedged volume (MMMBtu)		37,735			38,854			42,194			42,194			—
Hedged differential ($/MMBtu)	$	(0.89	)	$	(0.89	)	$	(0.39	)	$	(0.39	)	$	—
Oil timing differential positions:
Trade month roll swaps:(3)
Hedged volume (MBbls)		5,982			6,315			6,315			840			—
Hedged differential ($/Bbl)	$	0.21		$	0.21		$	0.21		$	0.17		$	—

(1) As presented in the table above, the Company has certain outstanding fixed price oil swaps on 14,750 Bbls of daily production which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2016, December 31, 2017, and December 31, 2018, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

(2) Settle on the Panhandle Eastern Pipeline (“PEPL”) spot price of natural gas to hedge basis differential associated with natural gas production in the Mid-Continent Deep and Mid-Continent Shallow regions.

(3) The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent Deep, Mid-Continent Shallow and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the year ended December 31, 2011, the Company entered into commodity derivative contracts consisting of oil and natural gas swaps for certain years through 2016 and oil trade month roll swaps for October 2011 through December 2015. In September 2011, the Company canceled its oil and natural gas swaps for the year 2016 and used the realized gains of approximately $27 million to increase prices on its existing oil and natural gas swaps for the year 2012. Also, in September 2011, the Company paid premiums of approximately $33 million to increase prices on its existing oil puts for the years 2012 and 2013. In addition, during the fourth quarter of 2011, the Company paid premiums of approximately $52 million for put options and approximately $22 million to increase prices on its existing oil puts for 2012 and 2013, respectively.

Settled derivatives on natural gas production for the year ended December 31, 2011, included volumes of 64,457 MMMBtu at an average contract price of $8.24. Settled derivatives on oil production for the year ended December 31, 2011, included volumes of 7,917 MBbls at an average contract price of $85.70. Settled derivatives on natural gas production for the year ended December 31, 2010, included volumes of 57,160 MMMBtu at an average contract price of $8.66. Settled derivatives on oil production for the year ended December 31, 2010, included volumes of 4,650 MBbls at an average contract price of $99.68. The natural gas derivatives are settled based on the closing NYMEX future price of natural gas or the published PEPL spot price of natural gas on the settlement date, which occurs on the third day preceding the production month. The oil derivatives are settled based on the month’s average daily NYMEX price of light crude oil and settlement occurs on the final day of the production month.

Interest Rate Swaps

The Company may from time to time enter into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. If LIBOR is lower than the fixed rate in the contract, the Company is required to pay the counterparty the difference, and conversely, the counterparty is required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company does not designate interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.

In April 2010, the Company restructured its interest rate swap portfolio in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of the 2020 Senior Notes (see Note 6). In conjunction with the repayment of borrowings under its Credit Facility with proceeds from the issuance of 2020 Senior Notes, the Company canceled (before the contract settlement date) certain interest rate swap agreements for 2010 through 2013, resulting in realized losses of approximately $74 million. In September 2010, the Company canceled (before the contract settlement date) all of its remaining interest rate swap agreements in conjunction with the repayment of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuance of 2021 Senior Notes (see Note 6). The cancellation of the interest rate swap agreements in September 2010 resulted in a realized loss of approximately $50 million. At December 31, 2011, and December 31, 2010, the Company had no outstanding interest rate swap agreements.

Balance Sheet Presentation

The Company’s commodity derivatives and, when applicable, its interest rate swap derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:

	December 31,
	2011		2010
	(in thousands)
Assets:
Commodity derivatives	$	880,175	$	637,836
Liabilities:
Commodity derivatives	$	320,835	$	398,902

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, when applicable, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $880 million at December 31, 2011. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives and, when applicable, its interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on derivatives, including realized and unrealized gains and losses, are reported on the consolidated statements of operations in “gains (losses) on oil and natural gas derivatives” and “losses on interest rate swaps.” Realized gains (losses), excluding canceled derivatives, represent amounts related to the settlement of derivative instruments, and for commodity derivatives, are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are noncash items.

The following presents the Company’s reported gains and losses on derivative instruments:

	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Realized gains (losses):
Commodity derivatives	$	230,237	$	307,587		$	400,968
Interest rate swaps		—		(8,021	)		(42,881	)
Canceled derivatives		26,752		(123,865	)		48,977
	$	256,989	$	175,701		$	407,064
Unrealized gains (losses):
Commodity derivatives	$	192,951	$	(232,376	)	$	(591,379	)
Interest rate swaps		—		63,978			16,588
	$	192,951	$	(168,398	)	$	(574,791	)
Total gains (losses):
Commodity derivatives	$	449,940	$	75,211		$	(141,374	)
Interest rate swaps		—		(67,908	)		(26,353	)
	$	449,940	$	7,303		$	(167,727	)

During the year ended December 31, 2011, the Company canceled (before the contract settlement date) its oil and natural gas swaps for the year 2016 and used the realized gains of approximately $27 million to increase prices on its existing oil and natural gas swaps for the year 2012. During the year ended December 31, 2010, the Company canceled (before the contract settlement date) all of its interest rate swap agreements resulting in realized losses of approximately $124 million.

During the year ended December 31, 2009, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized net gains of approximately $49 million. Of this amount, realized net gains of approximately $45 million, along with an incremental premium payment of approximately $49 million, were used to reposition the Company’s commodity derivative portfolio in July 2009, when the Company canceled oil and natural gas derivative contracts for years 2012 through 2014 to raise prices for oil and natural gas derivative contracts in years 2010 and 2011.

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Other Property and Equipment

12 Months Ended

Dec. 31, 2011

Other Property and Equipment

Note 9—Other Property and Equipment

Other property and equipment consists of the following:

	December 31,
	2011			2010
	(in thousands)
Natural gas compression plant and pipeline	$	129,863		$	96,624
Buildings and leasehold improvements		16,158			10,874
Vehicles		13,653			10,127
Drilling and other equipment		3,645			1,827
Furniture and office equipment		29,972			17,529
Land		3,944			2,922
		197,235			139,903
Less accumulated depreciation		(48,024	)		(35,151	)
	$	149,211		$	104,752

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Asset Retirement Obligations Reconciliation (Detail) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Asset retirement obligations rollforward
Asset retirement obligations, beginning of the period	$ 71,142	$ 42,945	$ 33,135
Liabilities added from acquisitions	34,096	19,853	6,976
Liabilities added from drilling	574	1,277	309
Current year accretion expense	3,373	4,140	2,694
Settlements	(1,506)	(2,218)	(169)
Revision of estimates	942	5,145
Asset retirement obligations, end of the period	$ 108,621	$ 71,142	$ 42,945

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Reconciliation of Numerators and Denominators of Basic and Diluted Per Unit Computations for Net Income Loss (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Earnings Per Share, Basic and Diluted, by Common Class [Line Items]
Net income (loss) allocated to units	$ 237,086	$ 237,109	$ 230,884	$ (209,573)	$ 438,439	$ (114,288)	$ (295,841)
Income allocated to unvested restricted units	(2,232)	(2,475)	(2,735)	(2,439)	(4,739)
Net income (loss) available to common unitholders, basic	$ 234,854	$ 234,634	$ 228,149	$ (212,012)	$ 433,700	$ (114,288)	$ (295,841)
Weighted average units outstanding
Basic net income (loss) per unit (in units)	197,507	175,035	195,382	169,104	172,004	142,535	119,307
Dilutive effect of unit equivalents (in units)	653	762	657		725
Diluted net income (loss) per unit (in units)	198,160	175,797	196,039	169,104	172,729	142,535	119,307
Earnings per share reconciliation
Basic income (loss) per unit (in usd per unit)	$ 1.19	$ 1.34	$ 1.17	$ (1.25)	$ 2.52	$ (0.80)	$ (2.48)
Dilutive effect of unit equivalents		$ (0.01)	$ (0.01)		$ (0.01)
Diluted income (loss) per unit (in usd per unit)	$ 1.19	$ 1.33	$ 1.16	$ (1.25)	$ 2.51	$ (0.80)	$ (2.48)

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Asset Retirement Obligations - Additional Information (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of Changes in Asset Retirement Obligations [Line Items]
Future inflation factor used in the calculation of the asset retirement obligations	2.00%	2.00%	2.00%	2.00%
Credit adjusted risk-free interest rate for the calculation of the asset retirement obligations	7.36%	7.50%	8.60%	9.60%

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Fair Value Measurements on a Recurring Basis (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Commodity Contracts

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:

	June 30, 2012
	Level 2		Netting(1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	1,730,071	$	(316,224	)	$	1,413,847
Liabilities:
Commodity derivatives	$	319,935	$	(316,224	)	$	3,711

(1) Represents counterparty netting under agreements governing such derivatives.

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:

	Fair Value Measurements on a Recurring Basis December 31, 2011
	Level 2		Netting(1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	880,175	$	(303,272	)	$	576,903
Liabilities:
Commodity derivatives	$	320,835	$	(303,272	)	$	17,563

(1) Represents counterparty netting under agreements governing such derivatives.

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Unit Options Activity (Detail) (Unit Options, USD $)	12 Months Ended
	Dec. 31, 2011 Year
Unit Options
Unit Options Activity [Roll Forward]
Outstanding, beginning (in units)	1,720,393
Exercised (in units)	(310,400)
Outstanding, ending (in units)	1,409,993
Exercisable (in units)	1,282,526
Weighted Average Exercise Price Per Unit [Abstract]
Outstanding, beginning (in dollars per unit)	$ 22.48
Exercised (in dollars per unit)	$ 23.99
Outstanding, ending (in dollars per unit)	$ 22.14
Exercisable (in dollars per unit)	$ 22.76
Weighted Average Grant Date Fair Value Per Unit [Abstract]
Outstanding, beginning (in dollars per unit)	$ 3.05
Exercised (in dollars per unit)	$ 3.83
Outstanding, ending (in dollars per unit)	$ 2.87
Exercisable (in dollars per unit)	$ 3.11
Weighted Average Remaining Contractual Life in Years [Abstract]
Outstanding, beginning (in years)	6.71
Outstanding, ending (in years)	5.83
Exercisable (in years)	5.70

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Income Taxes

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Income Taxes

Note 12—Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to unitholders. Limited liability companies are subject to Texas margin tax. Limited liability companies were also subject to state income taxes in the state of Michigan during the three months and six months ended June 30, 2012. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company. Amounts recognized for income taxes are reported in “income tax expense” on the condensed consolidated statements of operations.

Note 14—Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the states of Texas and Michigan, with income tax liabilities and/or benefits of the Company passed through to its unitholders. Limited liability companies are subject to state income taxes in Texas and Michigan and certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the states of Texas and Michigan and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company, except as set forth in the tables below.

The Company’s taxable income or loss, which may vary substantially from the net income or net loss reported in the consolidated statements of operations, is includable in the federal and state income tax returns of each unitholder. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholder’s tax attributes.

Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax benefit (expense) from continuing operations consisted of the following:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Current taxes:
Federal	$	(4,551	)	$	(65	)	$	(1,063	)
State		(605	)		(1,088	)		(678	)
Deferred taxes:
Federal		1,148			(2,862	)		5,307
State		(1,458	)		(226	)		655
	$	(5,466	)	$	(4,241	)	$	4,221

As of December 31, 2011, the Company’s taxable entities had approximately $8 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2031.

Income tax benefit (expense) differed from amounts computed by applying the federal income tax rate of 35% to pre-tax income (loss) from continuing operations as a result of the following:

	Year Ended December 31,
	2011			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%
State, net of federal tax benefit		0.5			(1.2	)		—
Loss excluded from nontaxable entities		(34.4	)		(37.5	)		(34.3	)
Other items		0.1			(0.1	)		0.7
Effective rate		1.2	%		(3.8	)%		1.4	%

Significant components of the deferred tax assets and liabilities were as follows:

	December 31,
	2011			2010
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	159		$	717
Unit-based compensation		9,146			6,234
Other		3,606			3,513
Valuation allowance		—			(217	)
Total deferred tax assets		12,911			10,247
Deferred tax liabilities:
Other accruals		—			(2,755	)
Property and equipment principally due to differences in depreciation		(8,226	)		(4,323	)
Other		(1,646	)		179
Total deferred tax liabilities		(9,872	)		(6,899	)
Net deferred tax assets	$	3,039		$	3,348

Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:

	December 31,
	2011			2010
	(in thousands)
Deferred tax assets	$	8,279		$	5,265
Deferred tax liabilities		(589	)		(3,105	)
Other current assets	$	7,690		$	2,160
Deferred tax assets	$	4,632		$	4,982
Deferred tax liabilities		(9,283	)		(3,794	)
Other noncurrent assets (liabilities)	$	(4,651	)	$	1,188

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2011, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

In accordance with the applicable accounting standard, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy in identifying uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2011, and December 31, 2010.

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Oil and Natural Gas Properties

6 Months Ended

Jun. 30, 2012

Oil and Natural Gas Properties

Note 4—Oil and Natural Gas Properties

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:

	June 30, 2012			December 31, 2011
	(in thousands)
Proved properties:
Leasehold acquisition	$	7,460,077		$	6,040,239
Development		2,019,012			1,484,486
Unproved properties		516,659			310,925
		9,995,748			7,835,650
Less accumulated depletion and amortization		(1,426,132	)		(1,033,617	)
	$	8,569,616		$	6,802,033

Impairment of Proved Properties

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

Based on the analysis described above, for the three months and six months ended June 30, 2012, the Company recorded a noncash impairment charge, before and after tax, of approximately $146 million associated with proved oil and natural gas properties related to lower commodity prices. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charge is included in “impairment of long-lived assets” on the condensed consolidated statements of operations. The Company recorded no impairment charge of proved oil and natural gas properties for the three months or six months ended June 30, 2011.

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Unit-Based Compensation Expenses (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share Based Compensation Expense	$ 6,663	$ 5,543	$ 14,834	$ 11,181	$ 22,243	$ 13,792	$ 15,089
Income tax benefit	2,462	2,408	5,481	4,132	8,219	5,096	5,968
Share-based Compensation Expense Recorded in General and Administrative Expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share Based Compensation Expense	6,289	5,290	13,911	10,694	21,131	13,450	14,743
Share-based Compensation Expense Recorded in Lease Operating Expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Allocated Share Based Compensation Expense	$ 374	$ 253	$ 923	$ 487	$ 1,112	$ 342	$ 346

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Oil and Natural Gas Properties (Tables)

6 Months Ended

Jun. 30, 2012

Oil and Natural Gas Properties

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:

	June 30, 2012			December 31, 2011
	(in thousands)
Proved properties:
Leasehold acquisition	$	7,460,077		$	6,040,239
Development		2,019,012			1,484,486
Unproved properties		516,659			310,925
		9,995,748			7,835,650
Less accumulated depletion and amortization		(1,426,132	)		(1,033,617	)
	$	8,569,616		$	6,802,033

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CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Balance Beginning		$ 3,428,910	$ 2,788,216	$ 2,788,216	$ 2,452,004	$ 2,760,686
Sale of units, net of underwriting discounts and expenses		731,455		651,522	809,774	279,299
Issuance of units		4,494		7,446	4,418	494
Purchase of units				(17,352)	(11,832)	(2,696)
Distributions to unitholders		(282,166)	(222,391)	(466,488)	(365,711)	(303,316)
Unit-based compensation expenses		14,834	11,181	22,243	13,792	15,089
Reclassification of distributions paid on forfeited restricted units				79	59	63
Excess tax benefit from unit-based compensation		3,252		4,805		577
Net income (loss)	237,086	230,884	(209,573)	438,439	(114,288)	(298,192)
Balance Ending	4,131,663	4,131,663		3,428,910	2,788,216	2,452,004
Units
Balance Beginning (in shares)		177,365	159,010	159,010	129,941	114,080
Sale of units, net of underwriting discounts and expenses (in shares)		21,090		17,514	28,750	14,950
Issuance of units		1,102		1,371	815	1,098
Cancellation of units (in shares)				(530)	(496)	(187)
Balance Ending (in shares)	199,557	199,557		177,365	159,010	129,941
Unitholders' Capital
Balance Beginning		2,751,354	2,549,099	2,549,099	2,098,599	2,109,089
Sale of units, net of underwriting discounts and expenses		731,455		651,522	809,774	279,299
Issuance of units		4,494		7,446	4,418	494
Cancellation of units				(17,352)	(11,832)	(2,696)
Distributions to unitholders		(282,166)		(466,488)	(365,711)	(303,316)
Unit-based compensation expenses		14,834		22,243	13,792	15,089
Reclassification of distributions paid on forfeited restricted units				79	59	63
Excess tax benefit from unit-based compensation		3,252		4,805		577
Balance Ending	3,223,223	3,223,223		2,751,354	2,549,099	2,098,599
Accumulated Income (Deficit)
Balance Beginning		677,556	239,117	239,117	353,405	651,597
Net income (loss)		230,884		438,439	(114,288)	(298,192)
Balance Ending	908,440	908,440		677,556	239,117	353,405
Treasury Units (at Cost)
Cancellation of units				17,352	11,832	2,696
Purchase of units				$ (17,352)	$ (11,832)	$ (2,696)

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Unitholders' Capital

6 Months Ended

12 Months Ended

Jun. 30, 2012

Dec. 31, 2011

Unitholders' Capital

Note 3—Unitholders’ Capital

Equity Distribution Agreement

In August 2011, the Company entered into an equity distribution agreement, pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.

In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $2 million in commissions and professional service expenses). The Company used the net proceeds for general corporate purposes, including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At June 30, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.

Public Offering of Units

In January 2012, the Company sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $28 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.

In March 2011, the Company sold 16,726,067 units representing limited liability company interests at $38.80 per unit ($37.248 per unit, net of underwriting discount) for net proceeds of approximately $623 million (after underwriting discount and offering expenses of approximately $26 million). The Company used a portion of the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Senior Notes and 2018 Senior Notes, and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Senior Notes and 2018 Senior Notes (see Note 6). The Company used the remaining net proceeds from the sale of units to finance a portion of the March 31, 2011, acquisition in the Williston/Powder River Basin region.

Distributions

Under the Company’s limited liability company agreement, the Company’s unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Distributions paid by the Company during the six months ended June 30, 2012, are presented on the condensed consolidated statement of unitholders’ capital. On April 24, 2012, the Company’s Board of Directors approved an increase in the quarterly cash distribution from $0.69 per unit to $0.725 per unit with respect to the first quarter of 2012, representing an increase of 5%. On July 24, 2012, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the second quarter of 2012. The distribution, totaling approximately $145 million, will be paid on August 14, 2012, to unitholders of record as of the close of business on August 7, 2012.

Note 3—Unitholders’ Capital

Equity Distribution Agreement

On August 23, 2011, the Company entered into an equity distribution agreement, pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million. In connection with entering into the agreement, the Company incurred expenses of approximately $423,000. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.

In September 2011, the Company issued and sold 16,060 units representing limited liability company interests at an average unit price of $38.25 for proceeds of approximately $602,000 (net of approximately $12,000 in commissions). In December 2011, the Company issued and sold 772,104 units representing limited liability company interests at an average unit price of $38.03 for proceeds of approximately $29 million (net of approximately $587,000 in commissions). In connection with the issue and sale of these units, the Company incurred professional service expenses of approximately $139,000. The Company used the net proceeds for general corporate purposes including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At December 31, 2011, units equaling approximately $470 million in aggregate offering price remained available to be issued and sold under the agreement.

Public Offering of Units

In March 2011, the Company sold 16,726,067 units representing limited liability company interests at $38.80 per unit ($37.248 per unit, net of underwriting discount) for net proceeds of approximately $623 million (after underwriting discount and offering expenses of approximately $26 million). The Company used a portion of the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Senior Notes and 2018 Senior Notes and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Senior Notes and 2018 Senior Notes (see Note 6). The Company used the remaining net proceeds from the sale of units to finance a portion of the March 31, 2011, acquisition in the Williston Basin.

In December 2010, the Company sold 11,500,000 units representing limited liability company interests at $35.92 per unit ($34.48 per unit, net of underwriting discount) for net proceeds of approximately $396 million (after underwriting discount and offering expenses of approximately $17 million). The Company used the net proceeds from the sale of these units to repay all outstanding indebtedness under its Credit Facility and for other general corporate purposes, including the partial notes redemption (see Note 6).

In March 2010, the Company sold 17,250,000 units representing limited liability company interests at $25.00 per unit ($24.00 per unit, net of underwriting discount) for net proceeds of approximately $414 million (after underwriting discount and offering expenses of approximately $17 million). The Company used a portion of the net proceeds from the sale of these units to finance the HighMount acquisition.

In October 2009, the Company sold 8,625,000 units representing limited liability company interests at $21.90 per unit ($21.024 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering expenses of approximately $8 million). The Company used the net proceeds from the sale of these units to reduce indebtedness under the Credit Facility.

In May 2009, the Company sold 6,325,000 units representing limited liability company interests at $16.25 per unit ($15.60 per unit, net of underwriting discount) for net proceeds of approximately $98 million (after underwriting discount and offering expenses of approximately $4 million). The Company used the net proceeds from the sale of these units to reduce indebtedness under the Credit Facility.

Equity Distribution Agreement and Public Offering of Units—Subsequent Events

In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $1 million in commissions). The Company used the net proceeds for general corporate purposes including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At January 31, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.

In January 2012, the Company also completed a public offering of units in which it sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $28 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.

Unit Repurchase Plan

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. During the year ended December 31, 2011, 529,734 units were repurchased at an average unit price of $32.76 for a total cost of approximately $17 million. During the year ended December 31, 2010, 486,700 units were repurchased at an average unit price of $23.79 for a total cost of approximately $12 million. During the year ended December 31, 2009, 123,800 units were repurchased at an average unit price of $12.99 for a total cost of approximately $2 million. All units were subsequently canceled.

At December 31, 2011, approximately $56 million was available for unit repurchase under the program. The timing and amounts of any such repurchases will be at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are repurchased at fair market value on the date of repurchase.

Issuance and Cancellation of Units

During the years ended December 31, 2010, and December 31, 2009, the Company purchased 9,055 units and 63,031 units for approximately $300,000 and $1 million, respectively, in conjunction with units received by the Company for the payment of minimum withholding taxes due on units issued under its equity compensation plan (see Note 5). All units were subsequently canceled. The Company purchased no units during the year ended December 31, 2011.

Distributions

Under the Agreement, Company unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Distributions paid by the Company are presented on the consolidated statements of unitholders’ capital. On January 27, 2012, the Company’s Board of Directors declared a cash distribution of $0.69 per unit with respect to the fourth quarter of 2011. The distribution, totaling approximately $138 million, was paid February 14, 2012, to unitholders of record as of the close of business February 7, 2012.

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Derivatives - Additional Information (Detail) (USD $)	1 Months Ended				2 Months Ended	3 Months Ended			6 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Apr. 30, 2010	Jul. 31, 2009	Dec. 31, 2011	Jun. 30, 2012 MmmBtu Mbbl	Dec. 31, 2011	Jun. 30, 2011 Mbbl MmmBtu	Jun. 30, 2012 Mbbl MmmBtu	Jun. 30, 2011 Mbbl MmmBtu	Dec. 31, 2011 MmmBtu Mbbl	Dec. 31, 2010 Mbbl MmmBtu	Dec. 31, 2009
Derivative [Line Items]
Amount of realized gain (loss) from cancelation before the settlement date of commodity derivative contracts											$ 27,000,000
Premiums paid for put options on oil and natural gas commodity derivative contracts	33,000,000			49,000,000	22,000,000		52,000,000		583,000,000
Volumes of natural gas production on settled derivatives (in MMMbtu)						34,438		16,106	58,080	32,178	64,457	57,160
Average contract price per MMBtu on settled derivatives						5.45		8.24	5.61	8.25	8.24	8.66
Volumes of oil production on settled derivatives (in MBbls)						2,731		1,839	5,308	3,671	7,917	4,650
Average contract price per barrel on settled derivatives						98.08		84.08	98.01	84.08	85.70	99.68
Amount of realized loss from cancelation before the settlement date of interest rate derivatives		50,000,000	74,000,000
Maximum Loss Upon All Counterparties Failing To Perform					880,000,000	1,700,000,000	880,000,000		1,700,000,000		880,000,000
Total realized gains (losses)											256,989,000	175,701,000	407,064,000
Cancelled Derivatives
Derivative [Line Items]
Total realized gains (losses)				$ 45,000,000							$ 26,752,000	$ (123,865,000)	$ 48,977,000

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Future Minimum Lease Payments (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Schedule of Operating Leases [Line Items]
2012	$ 5,652
2013	4,769
2014	4,598
2015	4,455
2016	2,950
Thereafter	9,053
Operating Leases, Future Minimum Payments Due, Total	$ 31,477

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Unit-Based Compensation

6 Months Ended

Jun. 30, 2012

Unit-Based Compensation

Note 5—Unit-Based Compensation

During the six months ended June 30, 2012, the Company granted an aggregate 953,668 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $35 million. The restricted units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
General and administrative expenses	$	6,289	$	5,290	$	13,911	$	10,694
Lease operating expenses		374		253		923		487
Total unit-based compensation expenses	$	6,663	$	5,543	$	14,834	$	11,181
Income tax benefit	$	2,462	$	2,408	$	5,481	$	4,132

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Net Deferred Tax Assets and Liabilities Classified in Consolidated Balance Sheets (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Balance Sheet Classification of Deferred Income Tax Assets and Liabilities [Line Items]
Deferred tax assets	$ 8,279	$ 5,265
Deferred tax liabilities	(589)	(3,105)
Other current assets	7,690	2,160
Deferred tax assets	4,632	4,982
Deferred tax liabilities	(9,283)	(3,794)
Other noncurrent assets (liabilities)	$ (4,651)	$ 1,188

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Operating Leases (Tables)

12 Months Ended

Dec. 31, 2011

Future Minimum Lease Payments

As of December 31, 2011, future minimum lease payments were as follows (in thousands):

2012	$	5,652
2013		4,769
2014		4,598
2015		4,455
2016		2,950
Thereafter		9,053
	$	31,477

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Operating Leases

12 Months Ended

Dec. 31, 2011

Operating Leases

Note 13—Operating Leases

The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2019. The Company recognized expense under operating leases of approximately $5 million, $5 million, and $4 million, for the years ended December 31, 2011, December 31, 2010, and December 31, 2009, respectively.

As of December 31, 2011, future minimum lease payments were as follows (in thousands):

2012	$	5,652
2013		4,769
2014		4,598
2015		4,455
2016		2,950
Thereafter		9,053
	$	31,477